BAL-002-2 Reliability Standard Petition

UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION

North American Electric Reliability
Corporation

)
)

Docket No. ____________

PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED RELIABILITY STANDARD
BAL-002-2
Gerald W. Cauley
President and Chief Executive Officer
North American Electric Reliability
Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-2560
(404) 446-2595 – facsimile

Charles A. Berardesco
Senior Vice President and General Counsel
Holly A. Hawkins
Associate General 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

January 29, 2016

TABLE OF CONTENTS
I. EXECUTIVE SUMMARY .................................................................................................... 3
II. NOTICES AND COMMUNICATIONS ................................................................................ 5
III. BACKGROUND .................................................................................................................... 6
A.
Regulatory Framework ..................................................................................................... 6
B.

NERC Reliability Standards Development Procedure ..................................................... 7

C.

Procedural History of Proposed Reliability Standard BAL-002-2................................... 7

IV. JUSTIFICATION FOR APPROVAL................................................................................... 13
A.
Proposed Reliability Standard BAL-002-2 .................................................................... 13
1.

Purpose and Overview of Proposed BAL-002-2 ........................................................ 13

2.

Responsible Entities ................................................Error! Bookmark not defined.16

3.

Enforceability of Proposed Reliability Standard BAL-002-2 .................................... 17

B.

Requirement by Requirement Justification .................................................................... 18

1.

Requirement R1 .......................................................................................................... 19

2.

Requirement R2 .......................................................................................................... 24

3.

Requirement R3 .......................................................................................................... 26

C.

Proposed NERC Glossary Definitions ........................................................................... 28

V. EFFECTIVE DATE .............................................................................................................. 34
VI. CONCLUSION ................................................................................................................. 3535
Exhibit A

Examples of Reportable Balancing Contingency Events

Exhibit B

Calculating Most Severe Single Contingency

Exhibit C

Proposed Reliability Standard BAL-002-2 (Clean and Redline)

Exhibit D

Implementation Plan

Exhibit E

BAL-002-2 Background Document

Exhibit F

Order No. 672 Criteria

Exhibit G

Analysis of Violation Risk Factors and Violation Severity Levels

Exhibit H

Summary of Development History and Complete Record of Development

Exhibit I

Mapping Document for BAL-002-2

Exhibit J

Mapping Document for EOP-011-1

Exhibit K

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 STANDARD
BAL-002-2
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 Standard BAL-002-2 (Disturbance Control Performance Contingency Reserve for Recovery from a Balancing Contingency Event) (Exhibit C), related
NERC Glossary definitions included in Exhibit D, the associated Implementation Plan (Exhibit
D), retirement of currently-effective Reliability Standard BAL-002-1 (Disturbance Control
Performance), and the Violation Risk Factors (“VRFs”) or Violation Severity Levels (“VSLs”)
(Exhibit G). These proposed revisions address and supersede the proposed interpretation under
pending Reliability Standard BAL-002-1.a. in Docket No. RM13-6-000. 4
Proposed Reliability Standard BAL-002-2 reflects revisions developed in Project 201014.1 (Phase 1 of Balancing Authority Reliability-based Controls). The proposed standard was
designed to properly identify entities that have the ability to take actions that will ensure reliable

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 FPA on July 20, 2006. N. Am. Elec. Reliability Corp., 116 FERC ¶ 61,062 (2006). Terms not
otherwise defined herein, are defined in the proposed Reliability Standard BAL-002-2 and the NERC Glossary.
4
Upon FERC’s approval of Reliability Standard BAL-002-2, NERC will file a notice withdrawal pursuant to
Rule 216 of the Rules of Practice and Procedure of the Federal Energy Regulatory Commission.
2

1

operation of the Bulk Power System by preparing responsible entities to balance resources and
demand and return the relevant Area Control Error (“ACE”) to defined values. Proposed
Reliability Standard BAL-002-2 has been developed to be a performance standard and to fulfill
the goals of the NERC Balancing Authority Controls Standards Authorization Request (“SAR”)
developed in Project 2007-05 and the NERC Reliability-Based Control SAR developed in
Project 2007-18, both of which incorporate Commission directives from Order No. 693. 5 The
NERC Board of Trustees adopted proposed Reliability Standard BAL-002-2 on November 5,
2015.
NERC requests that the Commission approve proposed Reliability Standard BAL-002-2
and associated NERC Glossary definitions as just, reasonable, not unduly discriminatory or
preferential, and in the public interest. As described below, NERC also requests approval of the
Implementation Plan (Exhibit D) and the Violation Risk Factors (“VRFs”) and Violation
Severity Levels (“VSLs”) for proposed Reliability Standard BAL-002-2. NERC requests that
the Commission accept the proposed Reliability Standard and associated NERC Glossary
definitions and VRFs and VSLs to become effective as prescribed in the Implementation Plan for
BAL-002-2.
As required by Section 39.5(a) of the Commission’s regulations, 6 this petition presents
the technical basis and purpose of proposed Reliability Standard BAL-002-2, a summary of the
development history (Exhibit H), and a demonstration that the proposed Reliability Standard
meets the criteria identified by the Commission in Order No. 672 (Exhibit F). 7

5

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).
6
18 C.F.R. § 39.5(a) (2014).
7
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

2

I.

EXECUTIVE SUMMARY
Reliable operation of the interconnected power system depends upon the ability of

responsible entities to balance resources and demand and to recover from a system contingency
through restoration of frequency and deployment of reserves necessary to replace capacity and
energy lost due to generation or transmission equipment outages. Proposed Reliability Standard
BAL-002-2 and the associated definitions, developed by the standard drafting team for Project
2010-14.1, address these considerations. The purpose of the standard is to ensure that “the
Balancing Authority or Reserve Sharing Group balances resources and demand and returns the
Balancing Authority's or Reserve Sharing Group's Area Control Error to defined values (subject
to applicable limits) following a Reportable Balancing Contingency Event.” The proposed
Reliability Standard BAL-002-2 and associated definitions improve upon the existing Reliability
Standard BAL-002-1 by streamlining currently effective requirements, clarifying specific
timelines for recovery, setting continent-wide requirements for events that impact frequency, and
coordinating with requirements in BAL-003-1.1 to implement a continent-wide reserve policy
with clear, objective parameters for measuring reserves.
In this petition, NERC requests that the Commission approve proposed Reliability
Standard BAL-002-2, which consolidates the six requirements in Reliability Standard BAL-0021 into three requirements by streamlining the required actions and improving existing language.
As described in more detail below, these requirements are supported by several proposed
associated NERC Glossary definitions, along with a revised Applicability section that
incorporates language from the existing standard. Proposed Reliability Standard BAL-002-2 will

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).

3

achieve its stated reliability goal by requiring responsible entities to maintain and deploy energy
reserves and to stabilize system frequency through identification of a Reportable ACE deviation
and restoration of Reporting ACE to defined values after a system disturbance. The proposed
standard will also require the responsible entity to maintain an Operating Process to ensure
maintenance of Contingency Reserves to a level at least equal to the responsible entity’s Most
Severe Single Contingency (“MSSC”). While not required, these Contingency Reserves may
include readiness to reduce Firm Demand and successful deployment and recovery of these
reserves upon a Reportable Balancing Contingency Event. By doing so, proposed Reliability
Standard BAL-002-2 creates and implements a continent-wide reserve policy to ensure that
responsible entities will always have adequate Contingency Reserves to be deployed as
necessary. Further, entities will be required to document each Reportable Balancing
Contingency Event and restore reserves necessary to address other events.
In addition to proposed Reliability Standard BAL-002-2, NERC proposes Glossary
definitions of Balancing Contingency Event, MSSC, Reportable Balancing Contingency Event,
Contingency Event Recovery Period, Contingency Reserve Restoration Period, Pre-Reporting
Contingency Event ACE Value, Reserve Sharing Group Reporting ACE, and Contingency
Reserve to clarify obligations and facilitate effective implementation of the proposed standard.
Together, the proposed Reliability Standard BAL-002-2 and associated Glossary definitions will
address Balancing Contingency Events within the MSSC (which may include multiple Balancing
Contingency Events, as explained below) in an effort to ensure responsible entities retain
flexibility to maintain service to Demand, while managing reliability, and to avoid duplication
with other Reliability Standards. The proposed standard and definitions will also avoid any gaps
in reliability coverage and will address outstanding directives from Order No. 693 regarding a

4

contingent-wide contingency reserve policy. 8 The proposed standard would also operate in
coordination with requirements under other Reliability Standards, including BAL-001-2, BAL003-1, TOP-007-0, EOP-002-3, and EOP-011-1, that may be implicated upon a significant
system disruption. 9
II.

NOTICES AND COMMUNICATIONS
Notices and communications with respect to this filing may be addressed to the

following: 10
Holly A. Hawkins*
Associate General 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]

8

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]

Order No. 693 at P 344.
Reliability Standard BAL-002-2 is not intended to address events greater than a Responsible Entity’s Most
Severe Single Contingency, as these large multi-unit events are addressed by various elements of other standards.
For example, the Balancing Authority ACE Limit in BAL-001-2 looks at Interconnection frequency to provide a
range in which a Balancing Authority should strive to operate as well as a 30-minute period to address instances
when the Balancing Authority is outside of that range. As another example, Reliability Standard TOP-007-0
addresses transmission line loading to account for transmission overloads if certain units were lost and reserves
responded.
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.
9

5

III.

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 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 regulations requires the
ERO to file with the Commission for its approval each Reliability Standard that the ERO
proposes should become mandatory and enforceable in the United States, and each modification
to a Reliability Standard that the ERO proposes should be made effective. 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. Pursuant to Section 215(d)(2) of the FPA 15 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. 16

11
12
13
14
15
16

16 U.S.C. § 824o (2012).
Id. § 824o(b)(1).
Id. § 824o(d)(5).
18 C.F.R. § 39.5(a).
16 U.S.C. § 824o(d)(2).
18 C.F.R. § 39.5(c)(1).

6

B.

NERC Reliability Standards Development Procedure

The proposed Reliability Standard was developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development process. 17 NERC
develops Reliability Standards in accordance with Section 300 (Reliability Standards
Development) of the NERC Rules of Procedure (“ROP”) and the NERC Standard Processes
Manual (“SPM”). 18
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, 19 and thus
satisfy certain of the criteria for approving Reliability Standards. 20 The ANSI-accredited
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 of Proposed Reliability Standard BAL-002-2

In Order No. 693, the Commission evaluated 107 Reliability Standards, including
Reliability Standard BAL-002-0 (Disturbance Control Performance), which requires Balancing

17

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.”).
18
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.
19
116 FERC ¶ 61,062 at P 250.
20
Order No. 672 at PP 268, 270.

7

Authorities (“BA”), Reserve Sharing Groups (“RSG”), and regional reliability organizations to
use contingency reserves to balance resources and demand to return Interconnection frequency to
within defined limits following a reportable disturbance. In that order, the Commission
approved Reliability Standard BAL-002-0 and directed development of modifications that (i)
include a Requirement that explicitly provides that Demand Side Management may be used as a
contingency reserve resource; (ii) incorporate a continent-wide contingency reserve policy; and
(iii) refer to the ERO rather than NERC Operating Committee in Requirements R4.2 and R6.2. 21
The Commission also directed modification of Reliability Standard BAL-002-0 “in a manner that
recognizes the loss of transmission as well as generation, thereby providing a realistic simulation
of possible events that might affect the contingency reserves.” 22 Other directives in Order No.
693 instructed NERC to develop (i) “a modification to the Reliability Standard requiring that any
single reportable disturbance that has a recovery time of 15 minutes or longer be reported as a
violation[;]” and (ii) a modification to “define a significant deviation and a reportable event,
taking into account all events that have an impact on frequency, e.g., loss of supply, loss of load
and significant scheduling problems, which can cause frequency disturbances and to address how
balancing authorities should respond.” 23
After issuance of Order No. 693, BAL-002-0 was revised to address the Commission’s
directives to (i) “develop a modification…that refers to the ERO rather than to the NERC
Operating Committee in Requirements R4.2 and R6.2….” and (ii) “modify this Reliability

21

Order No. 693, at P 356.
Id.
23
Id. at PP 354-355 (adding, at P 355, “As suggested by NRC, this or a related Reliability Standard should
also include a frequency response requirement. The present Control Performance Standards represent the monthly
and yearly averages which are appropriate for measuring long-term trends but may not be appropriate for measuring
short-term events. In addition, the measures should be available to the balancing authorities to assist in real-time
operations.”).
22

8

Standard to substitute Regional Entity for regional reliability organization as the compliance
monitor.” 24 As noted in the petition for Reliability Standard BAL-002-1, other directives from
Order No. 693 were not addressed at that time due to their technical complexity. 25 The
Commission approved Reliability Standard BAL-002-1 in a letter order issued on January 10,
2011. 26 Over the course of the next several years, NERC and industry continued reviewing
BAL-002 to address the Commission’s remaining directives from Order No. 693 and to clarify
confusion regarding applicable requirements.
On July 28, 2010, the NERC Standards Committee (“SC”) approved the merger of
existing Project 2007-05 (Balancing Authority Controls) and Project 2007-18 (Reliability-based
Controls) as Project 2010-14 (Balancing Authority Reliability-based Controls) (the “Project”),
given the inherent overlap in those projects, to continue addressing remaining Commission
directives from Order No. 693 that were not addressed in the development of BAL-002-1.
Specifically, this consolidated effort would, among other things, address the FERC Order No.
693 directive to create a continent-wide Contingency Reserve standard through revisions to
Reliability Standards BAL-002-1 (Disturbance Control Performance) and BAL-001-1a (later
superseded by BAL-001-1) (Real Power Balancing Control Performance), 27 and development of
new Reliability Standards BAL-012-1 (Operating Reserve Policy) and BAL-013-1 (Large Loss
of Load Performance). After initial SC approval of the Project, on July 13, 2011, the SC
approved the separation of the Project into two phases and moved Phase 1 of the Project (Project

24

Id. at PP 321 and 356.
BAL-002-1 Petition, at p. 17.
26
North American Electric Reliability Corporation, 134 FERC ¶ 61,015 (2011); and Petition of the North
American Electric Reliability Corporation for Approval of Proposed Modifications to Reliability Standards BAL002-1; EOP-002-3; FAC-002-1; MOD-021-2; PRC-004-2; and VAR-001-2, Docket No. RD10-15-000 (filed Sept. 9,
2010) (“BAL-002-1 Petition”).
27
N. Am. Elec. Reliability Corp., Docket No. RD13-11-000 (Oct. 16, 2013) (unpublished letter order)
(approving BAL-001-1).
25

9

2010-14.1 Balancing Authority Reliability-based Controls – Reserves), which is the subject of
this petition, into formal standards development.
The Project initially included revisions to BAL-001-0.1a (Real Power Balancing Control
Performance) and BAL-002-1 (Disturbance Control Performance) and development of two new
standards, BAL-012-1 (Operating Reserve Policy) and BAL-013-1 (Large Loss of Load
Performance). In 2013, the standard drafting team (“SDT”) for the Project ceased development
of BAL-012-1 and BAL-013-1 based on industry comments and ongoing development of related
Reliability Standard revisions that resolved surviving issues. Meanwhile, during development in
the Project, NERC developed a Reliability Standard Interpretation of BAL-002-1 pursuant to
Section 7.0 of the SPM in Appendix 3A of the NERC ROP 28 based on a request for
interpretation submitted by the Northwest Power Pool Reserve Sharing Group (“NWPP”). Later
in 2013, NERC filed a petition seeking approval for the proposed interpretation of BAL-002-1,
referred to as BAL-002-1a, stating that the proposed interpretation was intended to prevent
Registered Entities from shedding load to avoid possible violations of BAL-002-1. The
interpretation also proposed to clarify that:
(1) a Disturbance that exceeds the most severe single Contingency, regardless if it is a
simultaneous Contingency or nonsimultaneous multiple Contingency, would be a
reportable event, but would be excluded from compliance evaluation; (2) a preacknowledged Reserve Sharing Group would be treated in the same manner as an
individual Balancing Authority; however, in a dynamically allocated Reserve Sharing
Group, exclusions are only provided on a Balancing Authority member by member basis;
and (3) an excludable Disturbance was an event with a magnitude greater than the
magnitude of the most severe single Contingency. 29

28

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.
29
Petition of the North American Electric Reliability Corporation for Approval of Interpretation to BAL-0021 - Disturbance Control Performance, Docket No. RM13-6-000, at p. 2 (filed Feb. 12, 2013) (“Interpretation
Petition”).

10

In its Interpretation Petition, NERC acknowledged that the proposed interpretation differed from
a settlement reached in PacifiCorp, noting that the settlement was limited to the unique facts of
that case and that the settlement did not establish legal precedent. 30 In its subsequent Notice of
Proposed Rulemaking, issued on May 16, 2013, the Commission proposed to remand the
proposed interpretation on procedural grounds, stating that “interpretations can only clarify, not
change, a Reliability Standard.” 31 The proposed interpretation has been pending with the
Commission since 2013, and development under the Project has continued. The proposed BAL002-2 standard addresses and supersedes the proposed interpretation under pending Reliability
Standard BAL-002-1.a. in Docket No. RM13-6-000.
Given clear industry consensus for approval of BAL-001-2, in 2014, NERC proceeded to
file Reliability Standard BAL-001-2 with the Commission as developed through the Project to
define Balancing Authority Area Control Error (“ACE”) limits as a function of Interconnection
frequency. 32 In its Supplemental Information filing, NERC noted that revisions to Reliability
Standard BAL-002 were “in development and w[ould] complement the proposed revisions to the
BAL-001-2 Reliability Standard and w[ould] also address the Commission’s concerns in Order
No. 693 regarding the need to define reportable events.” 33 The Commission accepted BAL-001-

30

Id. at pp. 16-17 (discussing the difference between the interpretation and the Commission determination in
PacifiCorp, 137 FERC ¶ 61,176 at n. 5 (2011) (“Enforcement and NERC concluded that BAL-002-0 Requirement
R4 applies any time there is a Reportable Disturbance regardless of the number or type of contingencies and that this
requirement is not altered by the Additional Compliance Information in Section D.1.4 of BAL-002-0. In Order No.
693, in which the Commission approved this standard, among others, the Commission emphasized that compliance
was determined by the requirements, not other parts of a Reliability Standard….”) (internal citations omitted)).
31
Electric Reliability Organization Interpretation of Specific Requirements of the Disturbance Control
Performance Standard, 143 FERC ¶ 61,138, at PP 18 and 23 (2013).
32
Petition of the North American Electric Reliability Corporation for Approval of Reliability Standard BAL001-2- Real Power Balancing Control Performance, Docket No. RM14-10-000 (filed Apr. 2, 2014); and
Supplemental Information to Petition of the North American Electric Reliability Corporation for Approval of
Reliability Standard BAL-001-2-Real Power Balancing Control Performance (“Supplemental Information filing”),
Docket No. RM14-10-000 (filed May 9, 2014).
33
Id. at p. 5.

11

2 in Order No. 810 on April 16, 2015. 34 In approving Reliability Standard BAL-001-2, the
Commission noted that BAL-001-2 satisfied the Order No. 693 directive on BAL-002-0 to “to
define a significant deviation and a reportable event, taking into account all events that have an
impact on frequency…” 35 Throughout this regulatory proceeding, the SDT for the Project
continued to address the remaining Commission directives related to BAL-002-0 that were
evinced in Order No. 693.
Until October of 2015, over five years since initial consolidation of the Project into its
current form, revised versions of Reliability Standard BAL-002-2 were developed by the Project
SDT and balloted for stakeholder review. During that time, seven iterations of Reliability
Standard BAL-002-2 were posted for industry feedback and ballot, and after each ballot, the
standard was revised to account for industry concerns. On October 8, 2015, industry
stakeholders approved a final version of BAL-002-2, and on November 5, 2015, the NERC
Board of Trustees approved the standard.
As described above, proposed Reliability Standard BAL-002-2 is the culmination of
efforts under the Project, and it represents substantial improvement over the existing standard
and satisfies all remaining directives on prior Reliability Standard BAL-002-0. As such, the
proposed standard is intended to replace and retire Reliability Standard BAL-002-1 and
supersede the proposed interpretation under pending Reliability Standard BAL-002-1.a. A
review of the foregoing procedural history, the summary of development history, and complete
record of development for Reliability Standard BAL-002-2 are attached herein as Exhibit H.
The Project SDT Roster is attached as Exhibit K.

34

Real Power Balancing Control Performance Reliability Standard, Order No. 810, 151 FERC ¶ 61,048
(April 16, 2015).
35
Id. at P 4 (citing Order No. 693, at P 355 and referencing statements in the Notice of Proposed Rulemaking,
149 FERC ¶ 61,139 at PP 18-19 (2014), reh’g denied, 152 FERC ¶ 61,176 (2015).

12

IV.

JUSTIFICATION FOR APPROVAL
As discussed in Exhibit F, proposed Reliability Standard BAL-002-2 satisfies the

Commission’s criteria for standard development set forth in Order No. 672. Additionally, as
explained throughout this petition, the standard satisfies remaining directives on Reliability
Standard BAL-002-0 from Order No. 693 and is just, reasonable, not unduly discriminatory or
preferential, and in the public interest. The following subsections provide: (A) a description of
the proposed standard, its reliability purpose, responsible entities for compliance, and
enforceability of the proposed Reliability Standard; (B) justification for the proposed Reliability
Standard, detailing the proposed Requirements; and (C) justification for the new and revised
NERC Glossary definitions.
A.

Proposed Reliability Standard BAL-002-2
1.

Purpose and Overview of Proposed BAL-002-2

The purpose of proposed Reliability Standard BAL-002-2 is “[t]o ensure the Balancing
Authority or Reserve Sharing Group balances resources and demand and returns the Balancing
Authority's or Reserve Sharing Group's Area Control Error to defined values (subject to
applicable limits) following a Reportable Balancing Contingency Event.” The primary objective
of the proposed standard is, therefore, to ensure that the responsible entity is prepared to balance
resources and demand by requiring the maintenance of adequate reserves and deployment of
those reserves to return its ACE to defined values following a Reportable Balancing Contingency
Event. Proposed Reliability Standard BAL-002-2 is an improvement to BAL-002-1, as it
addresses additional outstanding Commission directives from Order No. 693 and it clarifies
obligations associated with achieving the objective of BAL-002 by streamlining and organizing
the responsibilities required therein, enhancing the obligation to maintain reserves, and further
defining events that predicate action under the standard. For a concise comparison of the
13

requirements and information in the currently-effective BAL-002-1 and the revised BAL-002-2,
please refer to the Mapping Document for BAL-002-2, attached herein as Exhibit I.
First, proposed Reliability Standard BAL-002-2 improves the language of each
requirement by consolidating overlapping requirements and streamlining elements of the
standard to improve efficiency and clarity. The proposed standard also clarifies the entities
responsible for compliance and removes unnecessary entities from compliance to capture only
those entities that are vital for reliability. Further, the standard more clearly defines Balancing
Contingency Event and Reportable Balancing Contingency Event to eliminate ambiguity
regarding the type of event that causes a frequency deviation for which action is necessary under
proposed Reliability Standard BAL-002-2, and it provides additional detail about the types of
resources that may be identified as Contingency Reserves. Finally, the proposed standard
ensures objectivity of the reserve measurement process by guaranteeing a Commissionsanctioned continent-wide reserve policy. 36 Given these improvements, proposed Reliability
Standard BAL-002-2 fulfills the Commission’s directive in Order No. 693 for NERC to “develop
a continent-wide contingency reserve policy through the Reliability Standards development
process, which should include uniform elements such as certain definitions and requirements as
discussed in this section.” 37
Proposed Reliability Standard BAL-002-2 fulfills a vital role in addressing frequency and
reserve issues, as described below. The proposed standard is intended to address frequency and
reserve issues when events occur that are within a responsible entity’s MSSC. However, the
proposed Standard does not address events above a responsible entity’s MSSC, because recovery
of ACE within a specified time period and restoration of Contingency Reserves due to unlikely

36
37

Order No. 693, at PP 340, 344.
Id.

14

events above a responsible entity’s MSSC is not within the scope of proposed Reliability
Standard BAL-002-2. Instead, Balancing Authorities and Reserve Sharing Groups must respond
to these large events under a coordinated suite of NERC standards including TOP-007-0, EOP002-3, and EOP-011-1 to ensure system stability and frequency control under a variety of
circumstances. Reliability Standard TOP-007-0 addresses transmission line loading by ensuring
that the Reliability Coordinator is apprised of exceedances of Interconnection Reliability
Operating Limits and System Operating Limits so that the Reliability Coordinator can direct
appropriate corrective action. Because transmission overloads could occur if certain units are
lost and reserves are deployed, TOP-007-0 is critical to ensure reliability upon an energy event.
Reliability Standard EOP-002-3 applies during the real-time time horizon, and it addresses
capacity and energy emergencies by requiring Balancing Authorities to take certain actions to
prepare for emergencies. Once the situations for which an entity was anticipating under EOP002-3 have occurred, Reliability Standard EOP-011-1 requires mitigation of energy emergencies
after the entity has entered a Reliability Coordinator declared emergency situation. This
integrated and coordinated approach would ensure reliability while also avoiding any gap in
coverage and providing means to address complex issues arising during events that exceed
MSSC.
Additionally, as noted in the “Background” section of proposed Reliability Standard
BAL-002-2, “Reliably balancing an Interconnection requires frequency management and all of
its aspects. Inputs to frequency management include Tie-Line Bias Control, Area Control Error
(ACE), and the various Requirements in NERC Resource and Demand Balancing Standards,
specifically BAL-001-2 Real Power Balancing Control Performance and BAL-003-1 Frequency
Response and Frequency Bias Setting.” Thus, when implemented together, Reliability Standards

15

BAL-001-2, BAL-003-1, and proposed BAL-002-2 guide entities towards establishing a
continent-wide contingency reserves policy pursuant to the Commission’s directive in Order No.
693.
First, Reliability Standard BAL-001-2 requires entities to operate based on
interconnection frequency and requires Balancing Authorities to respond to meet the Control
Performance Standard 1 and Balancing Authority ACE Limit, both terms defined in the NERC
Glossary. If an event larger than the MSSC occurs, the Balancing Authority ACE Limit will
likely decrease, and the Balancing Authority must respond to any exceedance of that value
within thirty minutes. In ensuring that the Control Performance Standard 1 is met, the Balancing
Authority may be required to respond in less than 10 minutes, thus strengthening the effects of
recovery under BAL-001-2. Second, to further support system frequency, Reliability Standard
BAL-003-1 requires Balancing Authorities to implement frequency response actions to sustain
Interconnection Frequency within predefined limits. This frequency responsive reserve
obligation, created in response to Order No. 693, stabilizes system operations from a frequency
perspective. Finally, as described throughout this petition, proposed Reliability Standard BAL002-2 completes development required by Order No. 693 to establish a continent-wide
contingency reserve policy by requiring responsible entities to review, maintain, and implement
an Operating Process for assurance of Contingency Reserves and to return the entity’s Reporting
ACE to predefined limits upon a Reportable Balancing Contingency Event.
2.

Responsible Entities

The requirements under proposed Reliability Standard BAL-002-2 apply to BAs and
RSGs. This proposed iteration of BAL-002 removes the regional reliability organization as a

16

responsible entity, based on a Commission directive. 38 Further, it adds a clarifying subpart to the
“Applicability” section to explain a distinction for Reserve Sharing Groups currently located in
Requirement R1.1 of currently effective BAL-002-1. To this end, Section 4.1.1.1 (the
“Applicability” section) of the proposed standard states that “[a] Balancing Authority that is a
member of a Reserve Sharing Group is the Responsible Entity only in periods during which the
Balancing Authority is not in active status under the applicable agreement or governing rules for
the Reserve Sharing Group.” Based on this clarification, a BA is not responsible for compliance
with BAL-002-2 when that BA is a member of a RSG for monitoring and deploying reserves for
that BA to balance resources and demand. Instead, the RSG is responsible for compliance with
BAL-002-2.
As explained above, the responsible entities for compliance with proposed Reliability
Standard BAL-002-2 are clear and unambiguous to ensure that the responsible party is held
accountable for performance of each Requirement. This change in Applicability in the revised
Reliability Standard BAL-002-2 represents an improvement over the existing standard.

3.

Enforceability of Proposed Reliability Standard BAL-002-2

Proposed Reliability Standard BAL-002-2 includes Measures that support each
Requirement to provide guidance to industry about compliance expectations and to ensure that
the Requirements are enforced in a clear, consistent, non-preferential manner and without
prejudice to any party. The proposed standard also includes VRFs and VSLs associated with
each Requirement, which are part of several elements used to determine an appropriate sanction
when the associated Requirement is violated. The VRFs assess the impact to reliability of
violating a specific Requirement. The VSLs provide guidance on the way that NERC will

38

Id. at P 321.

17

enforce the Requirements of the proposed Reliability Standards. All of the Requirements in
proposed Reliability Standard BAL-002-2 have been assigned a “Medium” VRF. This is
consistent with other Reliability Standards, such as BAL-001-1 and BAL-003-1. Exhibit G
includes a detailed analysis of the assignment of VRFs and the VSLs for the proposed Reliability
Standard. As described in that document, the VRFs and VSLs for proposed Reliability Standard
BAL-002-2 comport with NERC and Commission guidelines.
B.

Requirement by Requirement Justification

Proposed Reliability Standard BAL-002-2 consists of three Requirements that are
applicable to BAs and RSGs. These proposed Requirements comply with the Commission’s
outstanding directives in Order No. 693, 39 and the standard complies with criteria for Reliability
Standard development set forth in Order No. 672 as further supported in Exhibit F.
As reflected in the redlined version of Reliability Standard BAL-002-2, attached herein
as Exhibit C, and as explained below, Requirements R1 and R2 are modified versions of
currently effective Requirement R3 of Reliability Standard BAL-002-1. Similarly, currently
effective Requirement R4 of Reliability Standard BAL-002-1 has been incorporated within
Requirement R1 and the proposed definition of Contingency Event Recovery Period discussed
above. Requirement R5 of currently effective Reliability Standard BAL-002-1 has been moved
into Requirement R1 of proposed Reliability Standard BAL-002-2 and to the proposed definition
“Reserve Sharing Group Reporting ACE.” Finally, Requirement R6 of currently effective
Reliability Standard BAL-002-1 has been incorporated into Requirement R3 of proposed
Reliability Standard BAL-002-2 and the proposed definition of “Contingency Event Restoration
Period.”

39

Id. at P 356.

18

1.

Requirement R1

R1. The Responsible Entity experiencing a Reportable Balancing Contingency Event
shall: [Violation Risk Factor: Medium] [Time Horizon: Real-time Operations]
1.1. within the Contingency Event Recovery Period, demonstrate recovery by
returning its Reporting ACE to at least the recovery value of:
• zero (if its Pre-Reporting Contingency Event ACE Value was positive or
equal to zero); however, any Balancing Contingency Event that occurs
during the Contingency Event Recovery Period shall reduce the required
recovery: (i) beginning at the time of, and (ii) by the magnitude of, such
individual Balancing Contingency Event, or,
• its Pre-Reporting Contingency Event ACE Value (if its Pre-Reporting
Contingency Event ACE Value was negative); however, any Balancing
Contingency Event that occurs during the Contingency Event Recovery
Period shall reduce the required recovery: (i) beginning at the time of, and
(ii) by the magnitude of, such individual Balancing Contingency Event.
1.2. document all Reportable Balancing Contingency Events using CR Form 1.
1.3. deploy Contingency Reserve, within system constraints, to respond to all
Reportable Balancing Contingency Events, however, it is not subject to
compliance with Requirement R1 part 1.1 if:
1.3.1
•

•
•

1.3.2
•
•

the Responsible Entity:
is a Balancing Authority experiencing a Reliability Coordinator
declared Energy Emergency Alert Level or is a Reserve Sharing
Group whose member, or members, are experiencing a Reliability
Coordinator declared Energy Emergency Alert level, and
is utilizing its Contingency Reserve to mitigate an operating
emergency in accordance with its emergency Operating Plan, and
has depleted its Contingency Reserve to a level below its Most
Severe Single Contingency
or,
the Responsible Entity experiences:
multiple Contingencies where the combined MW loss exceeds its
Most Severe Single Contingency and that are defined as a single
Balancing Contingency Event, or
multiple Balancing Contingency Events within the sum of the time
periods defined by the Contingency Event Recovery Period and
Contingency Reserve Restoration Period whose combined
magnitude exceeds the Responsible Entity's Most Severe Single
Contingency.
19

Requirement R1 mandates certain actions that an entity must take upon occurrence of a
Reportable Balancing Contingency Event. Specifically, Requirement R1 obligates responsible
entities to (i) return Reporting ACE to defined values within the Contingency Event Recovery
Period (Requirement R1.1), (ii) document Reportable Balancing Contingency Events using CR
Form 1 (Requirement R1.2), and (iii) deploy Contingency Reserves to respond to Reportable
Balancing Contingency Events. Requirement R1.3 also provides certain limited exemptions
from the obligation for a responsible entity to restore Reporting ACE within the Contingency
Event Recovery Period found in Requirement R1.1 (please note, for clarity, that Requirement
R1.3 does not exempt responsible entities from responding to a Reportable Balancing
Contingency Event).
Requirement R1.1, which operates as a frequency management requirement, ensures that
a responsible entity will return its Reporting ACE to a predefined value within fifteen minutes
(or within the Contingency Event Recovery Period) to ensure stability of the system. The
predefined value for recovery is zero if the Pre-Reporting Contingency Event ACE Value was
greater than or equal to zero, or it is the value of the Pre-Reporting Contingency Event ACE
Value if that value is negative. However, the required recovery value can be reduced for both
situations if a Balancing Contingency Event occurs during the Contingency Event Recovery
Period. Further, the 15-minute threshold was identified by the Commission in Order No. 693 as
appropriate to recovery reserves. 40 Requirement R1.1 allows reprieve for total recovery after a
Reportable Balancing Contingency Event and a subsequent Balancing Contingency Event, as this
deduction of required recovery is necessary to provide responsible entities the opportunity to

40

Id. at PP 354-355.

20

initiate recovery from the Reportable Balancing Contingency Event and continue, in good faith,
to facilitate adequate recovery without sacrificing reliability.
Requirement R1.2 requires a responsible entity to document the Reportable Balancing
Contingency Events in its area using CR Form 1. The SDT determined that it is most efficient
and clear to require responsible entities to document events using a designated form that captures
all relevant information about the event, rather than providing specific criteria necessary for
proper documentation. The information obtained through CR Form 1 will supplement all other
information provided to the Regional Entity to show compliance with Requirement R1 after a
Reportable Balancing Contingency Event has occurred.
Pursuant to Requirement R1.3, responsible entities must deploy Contingency Reserves to
cover the loss caused by a Reportable Balancing Contingency Event. Requirements R1.3 works
in tandem with Requirement R1.1 and R2 to ensure a constant requisite level of Contingency
Reserves available for deployment. While including the affirmative obligation to deploy
Contingency Reserves after a Reportable Balancing Contingency Event, Requirement R1.3.1 and
R1.3.2 also exempt responsible entities from compliance with Requirement R1.1 if the entity
meets one of three exemptions detailed immediately below. 41 Requirement R1.3, in conjunction
with the definition of Reportable Balancing Contingency Event, addresses Commission concerns
in Order No. 693 outlined above by requiring applicable entities to respond to events and
measure performance.
a)

Requirement R1.3.1

As alluded to above, Requirement R1.3.1 excuses a responsible entity from the timeframe
for recovering its Reporting ACE to predefined limits if the responsible entity meets all of three

41

NERC notes that there are three exemptions, as Requirement R1.3.1 provides the first exemption and the
Requirement R1.3.2 contains two exemptions.

21

conditions. First, a responsible entity must be a BA or RSG whose member or members are
experiencing a Reliability Coordinator-declared Energy Emergency Alert level pursuant to
proposed Reliability Standard EOP-011-1. 42 Second, the responsible entity must be actively
utilizing its available Contingency Reserves to mitigate an operating emergency in accordance
with its emergency Operating Plan created to comply with EOP-011-1. Third, the Responsible
Entity must have depleted all of its Contingency Reserves to a level below its MSSC.
If each of these three circumstances exist simultaneously, a responsible entity is excused
from compliance with Requirement R1.1 (in that the entity is not bound to its time frame for
recovery of Reporting ACE) because the entity will be recovering from an emergency event
under EOP-011-1 and is not expected to have the resources to also comply with BAL-002-2.
This provision eliminates the existing conflict with EOP-011-1, as it removes undefined auditor
discretion when assessing compliance and allows the responsible entity flexibility to maintain
service to load while managing reliability. In other words, if a responsible entity meets all three
conditions contained within Requirement R1.3.1, the responsible entity has exhausted all of its
available resources and the Reliability Coordinator has declared an energy emergency. The
responsible entity will be subject to Reliability Standard EOP-011-1 for purposes of responding
to the event and must coordinate with the Reliability Coordinator to reestablish reliable operation
through creation of an Operating Plan. This iterative restoration process between the responsible
entity and a Reliability Coordinator through creation and implementation of an Operating Plan

42

The Commission approved Reliability Standard EOP-011-1, among others, on November 19, 2015 in Order
No. 818. Revisions to Emergency Operations Reliability Standards; Revisions to Undervoltage Load Shedding
Reliability Standards; Revisions to the Definition of “Remedial Action Scheme” and Related Reliability Standards,
153 ¶ 61,228 (Nov. 19, 2015) (Order No. 818). For a visual representation of how EOP-011-1 works in coordination
with other Reliability Standards to mitigate emergency events, see the Reliability Standard EOP-011-1 Mapping
Document, attached herein as Exhibit J.

22

under EOP-011-1 is adequate to maintain reliability and preferable to Requirement R1.1 in light
of immediate concerns, such as transmission frequency, voltage, line loading,.
Further, a responsible entity is still required to document the Reportable Balancing
Contingency Event and deploy Contingency Reserves to meet the Reportable Balancing
Contingency Event, as Requirement 1.3.1 does not exempt responsible entities from
Requirements R1.2 and R1.3. When recovery is complete, as outlined in the Emergency
Operating Plan under EOP-011, and the Reliability Coordinator removes the Energy Emergency
Alert level associated with the emergency event, Requirement R1.3.1 will no longer apply and
the responsible entity will again be responsible for compliance with the entirety of BAL-002-2.
Requirement R5 of Reliability Standard EOP-011-1 requires a Reliability Coordinator to declare
an energy emergency if the Balancing Authority is “experiencing a potential or actual Energy
Emergency.” Thus, given the relationship between Requirement R1.3.1 of Reliability Standard
BAL-002-2 and required RC and BA communications under Requirement R6 of Reliability
Standard EOP-011-1, it is unnecessary and would be redundant to include obligations in
proposed Reliability Standard BAL-002-2 regarding RC authorization for application of
Requirement R1.3.1. 43 Reliability Standard BAL-002-2 also eliminates any duplicative
reporting and inconsistencies with other standards. Accordingly, as explained above, the
exemptions under R1.3.1 do not interfere with maintenance of system reliability and coordinate
with Reliability Standard EOP-011-1.
b)

Requirement R1.3.2

Requirement R1.3.2 also excuses responsible entities from the timeframe for recovering
its Reporting ACE to predefined limits if the entity meets either one of two criteria (thereby

43

See e.g., the Reliability Standard EOP-011-1 Mapping Document, attached herein as Exhibit J.

23

providing the remaining two possible exemptions from Requirement R1.1). First, a responsible
entity is excused from Requirement R1.1 if the entity experiences more than one Contingency,
defined as a single Balancing Contingency Event, where the combined loss exceeds the MSSC.
As discussed under the proposed definitions, a “single” Balancing Contingency Event can
include otherwise single events separated from each other by one minute or less. Second, a
responsible entity is also excused from compliance with Requirement R1.1 if it experiences more
than one Balancing Contingency Event with a combined magnitude that exceeds the MSSC and
is within the sum of the time periods defined by the Contingency Event Recovery Period and
Contingency Reserve Restoration Period.
If an entity meets Requirements R1.3.1 or R1.3.2, the entity is excused compliance with
the requirement to return its Reporting ACE to the predefined value in Requirement R1.1. As
explained above, the three exclusions in Requirement R1.3.1 and R1.3.2 do not exempt
responsible entities from responding to a Reportable Balancing Contingency Event; rather, these
exclusions simply allow entities more time to return the Reporting ACE to the defined limits
than would otherwise be allowed. These exemptions from compliance are just and reasonable
and in the public interest because they providing additional time for responsible entities to
recover Reporting ACE if multiple events arise within one-minute, allowing the entity the
flexibility to continue recovery after multiple losses while maintaining service to meet demand
and managing reliability.
2.

Requirement R2

R2. Each Responsible Entity shall develop, review and maintain annually, and implement
an Operating Process as part of its Operating Plan to determine its Most Severe Single
Contingency and make preparations to have Contingency Reserve equal to, or greater
than the Responsible Entity’s Most Severe Single Contingency available for maintaining
system reliability. [Violation Risk Factor: Medium] [Time Horizon: Operations
Planning]
24

In Order No. 693, the Commission directed NERC to develop BAL-002 as a continentwide contingency reserve policy inclusive of an appropriate mix of operating reserve, spinning
reserve, and non-spinning reserve. After issuing Order No. 693, the Commission approved
BAL-003-1 to address frequency responsive reserve and the amount of frequency response
obligation required to adequately address potential loss of resources. Requirement R2 of
Reliability Standard BAL-002-2 continues the work begun by development of BAL-003-1 to
address this directive. In so doing, Requirement R2 establishes a uniform continent-wide
contingency reserve policy by requiring a responsible entity to create an Operating Process to
determine its MSSC and to assure maintenance of Contingency Reserves at least as great as the
entity’s MSSC.
Proper valuation of the MSSC is critical for ensuring reliable operation of the Bulk
Electric System. Requirement R2 works in conjunction with the definition of MSSC, discussed
below, to obligate Responsible entities to accurately calculate MSSC according to system models
maintained by the RSG or BA. Specifically, Requirement R2 requires responsible entities to
demonstrate proper design and implementation of an Operating Process that surveys all
contingencies, including single points of failure, to identify the event that would cause the
greatest loss of resource output used by the RSG or BA to meet Firm Demand and export
obligation (excluding export obligation for which Contingency Reserve is met by the Sink
BA). 44 Further, Requirement R2 supports Requirements R1 and R3 in BAL-002-2, as these
requirements rely on proper calculation of MSSC. A further explanation of how an entity may

44
Single points of failure in the context of transmission planning will be addressed in ongoing Project 201510: Single Points of Failure TPL-001 in response to Order No. 754. In that Order, the Commission directed FERC
staff to meet with to explore the reliability concern associated with single points of failure in the context of
transmission planning. See, Interpretation of Transmission Planning Reliability Standard, Order No. 754, 136 FERC
¶ 61,186 at PP 19-20 (2011).

25

calculate the MSSC, along with illustrative examples, has been prepared by the SDT and is
attached herein as Exhibit B.
As described above, the performance-based obligations in Requirement R2 of BAL-0022, along with previously approved BAL-003-1, collectively accomplish the tasks directed by the
Commission in Order No. 693 with respect to a continent-wide contingency reserves policy.
3.

Requirement R3

R3. Each Responsible Entity, following a Reportable Balancing Contingency Event, shall
restore its Contingency Reserve to at least its Most Severe Single Contingency, before the
end of the Contingency Reserve Restoration Period, but any Balancing Contingency
Event that occurs before the end of a Contingency Reserve Restoration Period resets the
beginning of the Contingency Event Recovery Period. [Violation Risk Factor: Medium]
[Time Horizon: Real-time Operations]
Requirement R3 requires responsible entities to restore Contingency Reserve within a
defined period (as delineated in the proposed definition of Contingency Reserve Restoration
Period) after a Reportable Balancing Contingency Event to ensure maintenance of sufficient
reserves. Specifically, Contingency Reserves must be restored to “at least its Most Severe Single
Contingency” to ensure that responsible entities may meet Firm Demand and export obligation.
This measure of assurance confirms adequacy of Contingency Reserves on an ongoing basis.
Contingency Reserves must be restored within the Contingency Reserve Restoration
Period, defined in this project as a period not exceeding 90 minutes following the end of the
Contingency Event Recovery Period, or 15 minutes after the first minute of resource output
decline. As such, responsible entities must recover Contingency Reserves within 105 minutes of
the occurrence of a Reportable Balancing Contingency Event in order to comply with
Requirement R3. This period is just and reasonable by providing adequate opportunity for a
responsible entity to recover from an event while also maintaining reliability and recovery of
reserves in a timely manner. If, however, an entity experiences another Balancing Contingency
26

Event before the end of the Contingency Reserve Restoration Period (or in the 90 minute period
following the end of the Contingency Event Recovery Period), the Contingency Reserve
Recovery Period resets to provide time and flexibility for an entity’s ongoing recovery. The
extended period to restore Contingency Reserve is triggered by a Balancing Contingency Event
(rather than a Reportable Balancing Contingency Event) that arises prior to the end of a
Contingency Reserve Restoration Period for a Reportable Balancing Contingency Event, due to
the heightened sensitivities applicable during such a Contingency Reserve Restoration Period.
The Contingency Reserve Recovery Period “reset” avoids punishing a responsible entity
for an unexpected event, occurring within Contingency Reserve Restoration Period, which may
make it infeasible to fully restore the requisite level of Contingency Reserves as intended. In
other words, R3 applies when a responsible entity experiencing a Reportable Balancing
Contingency Event has developed a plan for recovery of Contingency Reserves and has begun
restoration of its Contingency Reserves, but due to unforeseen circumstances, experiences
another Balancing Contingency Event before full recovery. This compounding loss inevitably
increases the total recovery necessary to replenish Contingency Reserves, thus making it more
difficult to replenish the reserves while also meeting current demand.
An entity implementing a properly executed Operating Plan for recovery of Contingency
Reserves that experiences a Reportable Balancing Contingency Event and a subsequent
Balancing Contingency Event within the Contingency Reserve Restoration Period should not be
held in non-compliance until the entity has had adequate opportunity to recover. As explained
above, the “reset” function of Requirement R3 is necessary and in the public interest, as it allows
entities to manage reliability of its system while properly recovering from an event within a

27

reasonable time. Several examples of an application of the “reset” feature can be found in the
Examples of Reportable Balancing Contingency Events document, attached herein as Exhibit A.
C.

Proposed NERC Glossary Definitions

NERC proposes eight definitions for inclusion in the NERC Glossary, included in
Exhibit C herein. NERC also proposes to retire the current definition of Contingency Reserve.
Below is the text of each proposed definition, followed by an explanation as to why the proposed
definitions are necessary and how they work as an integrated proposal to support implementation
of the proposed Reliability Standard BAL-002-2. As reflected in this Petition and further
demonstrated in the attached examples in Exhibit A and Exhibit B, the proposed definitions
work together to support implementation of proposed Reliability Standard BAL-002-2.
1.

Balancing Contingency Event

Balancing Contingency Event: Any single event described in Subsections (A), (B), or
(C) below, or any series of such otherwise single events, with each separated from the
next by one minute or less.
A. Sudden loss of generation:
a. Due to
i. unit tripping,
ii. loss of generator Facility resulting in isolation of the generator
from the Bulk Electric System or from the responsible entity’s
System, or
iii. sudden unplanned outage of transmission Facility;
b. And, that causes an unexpected change to the responsible entity’s ACE;
B. Sudden loss of an import, due to unplanned outage of transmission equipment
that causes an unexpected imbalance between generation and Demand on the
Interconnection.
C. Sudden restoration of a Demand that was used as a resource that causes an
unexpected change to the responsible entity’s ACE.
The proposed definition of Balancing Contingency Event is necessary to eliminate
potential confusion and ambiguity by setting forth the events or contingencies causing an
unexpected change to a responsible entity’s ACE that may give rise to a Reportable Balancing
28

Contingency Event obligating the BA or RSG to return ACE within defined values per the
Requirements of proposed Reliability Standard BAL-002-2. The proposed definition eliminates
ambiguities present in the existing effective version of BAL-002 by defining an event that causes
an unexpected change to the responsible entity’s ACE. As such, the proposed definition of
Balancing Contingency Event is necessary to assist a responsible entity in measuring responses
for any event or contingency that causes a frequency deviation, consistent with the
Commission’s directive in Order No. 693. 45
A Balancing Contingency Event can be a single event, as described in subsections A
through C of the definition, or more than one such event that is separated from the next by one
minute or less. The revised proposed definition of Balancing Contingency Event maintains the
existing sixty (60) second threshold from currently enforceable Reliability Standard BAL-002-1
for consolidating more than one event into a single event for purposes of compliance. This one
minute threshold is appropriate for purposes of determining whether otherwise multiple events
constitute a single Balancing Contingency Event because, rather than requiring responsible
entities to reset its restoration periods multiple times within a short period of time, a defined
threshold sets an articulable starting point for calculating restoration times for multiple
successive events by initiating the Contingency Event Recovery Period. In other words, a oneminute threshold ensures that an entity can aggregate multiple events within a minute given the
fact that events occurring within this truncated period of time can function as a single event for
purposes of recovery and compliance with the requirements of Reliability Standard BAL-002-2.
Examples of a sudden declines in a Reportable ACE and how this decline impacts an entity’s
obligations under Reliability Standard BAL-002-2 can be found in Exhibit A, attached herein.

45

Order No. 693, at P 355.

29

The definitions of MSSC and Contingency Reserve rely upon the proposed definition of
Balancing Contingency Event for proper application. The term Balancing Contingency Event
also affects substantive obligations under BAL-002-2 by requiring entities to take certain actions
upon the occurrence of a Balancing Contingency Event. For instance, an entity may reduce its
required recovery under Requirement R1.1 upon occurrence of a Balancing Contingency Event
occurring during the Contingency Event Recovery Period. Furthermore, given the relationship
between MSSC and Balancing Contingency Event mentioned above, the proposed definition of
Balancing Contingency Event supports implementation of (i) Requirement R2, which obligates a
responsible entity to determine its MSSC and maintain Contingency Reserves at least as great as
the MSSC, and (ii) Requirement R3, which requires restoration of MSSC after a Reportable
Balancing Contingency Event subject to an additional Balancing Contingency Event. Therefore,
the proposed definition of Balancing Contingency Event is integral to implementation of
proposed Reliability Standard BAL-002-2 and necessary to delineate responsibilities that will
foster system stability and ensure adequate reserves.
2.

Reportable Balancing Contingency Event

Reportable Balancing Contingency Event: Any Balancing Contingency Event
occurring within a one-minute interval of an initial sudden decline in ACE based on EMS
scan rate data that results in a loss of MW output less than or equal to the Most Severe
Single Contingency, and greater than or equal to the lesser amount of: (i) 80% of the
Most Severe Single Contingency, or (ii) the amount listed below for the applicable
Interconnection. Prior to any given calendar quarter, the 80% threshold may be reduced
by the responsible entity upon written notification to the Regional Entity.
•
•
•
•

Eastern Interconnection – 900 MW
Western Interconnection – 500 MW
ERCOT – 800 MW
Quebec – 500 MW

The definition of Reportable Balancing Contingency Event provides the scope of
obligations required under Requirements R1 and R3 of BAL-002-2. Specifically, these
30

requirements (discussed above) impose obligations on responsible entities to take certain
recovery actions upon the occurrence of a Reportable Balancing Contingency Event to sustain
Reporting ACE and adequate levels of Contingency Reserves.
The terms Reportable Balancing Contingency Event and Contingency Event Recovery
Period operate together to specify timing requirements for recoveries from Reportable Balancing
Contingency Events. For example, as detailed in connection with Requirements R1 and R3
above, occurrence of a Balancing Contingency Event after the occurrence of a Reportable
Balancing Contingency Event may subject responsible entities to different compliance
obligations. Exhibit A, attached herein, includes several examples that illustrate what events
would be deemed “Reportable Balancing Contingency Events” given the circumstances
surrounding each event.
3.

Most Severe Single Contingency (MSSC)

Most Severe Single Contingency (MSSC): The Balancing Contingency Event, due to a
single contingency as identified and maintained in the system models within the Reserve
Sharing Group (RSG) or a Balancing Authority’s area that is not part of a Reserve
Sharing Group, that would result in the greatest loss (measured in MW) of resource
output used by the RSG or a Balancing Authority that is not participating as a member of
a RSG at the time of the event to meet Firm Demand and export obligation (excluding
export obligation for which Contingency Reserve obligations are being met by the Sink
Balancing Authority).
See above discussion supporting the proposed definitions of Balancing Contingency
Event and Reportable Balancing Contingency Event, as well as the justification for Requirement
R2. For a further explanation of MSSC and illustrative examples for calculating an entity’s
MSSC, refer to Exhibit B, attached herein.

31

4.

Contingency Event Recovery Period

Contingency Event Recovery Period: A period that begins at the time that the resource
output begins to decline within the first one-minute interval of a Reportable Balancing
Contingency Event, and extends for fifteen minutes thereafter.
See above discussion supporting the proposed definitions of Balancing Contingency
Event and Reportable Balancing Contingency Event, as well as the justification for Requirement
R3.
5.

Contingency Reserve Restoration Period

Contingency Reserve Restoration Period: A period not exceeding 90 minutes
following the end of the Contingency Event Recovery Period.
See above discussion supporting the proposed definitions of Balancing Contingency
Event and Reportable Balancing Contingency Event, as well as the justification for Requirement
R3.
6.

Pre-Reporting Contingency Event ACE Value

Pre-Reporting Contingency Event ACE Value: The average value of Reporting ACE,
or Reserve Sharing Group Reporting ACE when applicable, in the 16-second interval
immediately prior to the start of the Contingency Event Recovery Period based on EMS
scan rate data.
See above discussion supporting the proposed definitions of Balancing Contingency
Event and Reportable Balancing Contingency Event, as well as the justification for Requirement
R3.
7.

Reserve Sharing Group Reporting ACE

Reserve Sharing Group Reporting ACE: At any given time of measurement for the
applicable Reserve Sharing Group (RSG), the algebraic sum of the ACEs (or equivalent
as calculated at such time of measurement) of the Balancing Authorities participating in
the RSG at the time of measurement.

32

Reserve Sharing Group Reporting ACE is term defining the unique calculation of
Reporting ACE for Reserve Sharing Groups. As further justification for why this term is
necessary, see, generally, the justification for Requirement R1.
8.

Contingency Reserve

Contingency Reserve: The provision of capacity that may be deployed by the Balancing
Authority to respond to a Balancing Contingency Event and other contingency requirements
(such as Energy Emergency Alerts as specified in the associated EOP standard). A Balancing
Authority may include in its restoration of Contingency Reserve readiness to reduce Firm
Demand and include it if, and only if, the Balancing Authority:
•
•

is experiencing a Reliability Coordinator declared Energy Emergency Alert level,
and
is utilizing its Contingency Reserve to mitigate an operating emergency in
accordance with its emergency Operating Plan.

The existing definition of Contingency Reserve focuses primarily on generation and does
not fully incorporate the use of demand-side management for balancing resources and demand to
return an entity’s ACE to defined values. The revised, proposed definition of Contingency
Reserve improves the existing definition by addressing a Commission directive in Order No. 693
to allow demand side management to be used as a resource for contingency reserve when
necessary.
In allowing entities to use demand side management as a resource for Contingency
Reserves in certain circumstances, the revised definition of Contingency Reserve, in conjunction
with proposed Reliability Standard BAL-002-2, establishes an “adequate level of reliability” by
requiring entities to plan for and recover from reportable disturbances but not requiring
responsible entities to shed firm load only to restore Contingency Reserves. Rather, as intended

33

by the SDT for BAL-002-2 and reiterated through its response to industry comments 46, an entity
must include “readiness to reduce Firm Demand” as an available Contingency Reserve upon the
occurrence of an event. In other words, shedding load, which would be an extreme action, is not
required to restore Contingency Reserves when those reserves have been depleted, but should be
considered a Contingency Reserve for deployment in response to the next event. The existing
definition of Contingency Reserve should be retired at midnight of the day immediately prior to
the effective date of BAL-002-2, in the jurisdiction in which the new standard is becoming
effective.
As demonstrated above and underscored by the justification in support of the proposed
Requirements, the proposed definitions will support proper implementation of proposed
Reliability Standard BAL-002-2 and ensure that BAs and RSGs balance resources and demand
and return ACE to defined values following a Reportable Balancing Contingency Event.
V.

EFFECTIVE DATE
NERC respectfully requests that the Commission accept the Implementation Plan for

BAL-002-2, included herein in Exhibit D. As explained in more detail in the Implementation
Plan, responsible entities will be required to comply with the standard on the first day of the first
calendar quarter that is six (6) months after this standard is approved by the Commission.

46

In the Background Document (Exhibit E), the SDT clearly stated that BAL-002-2 should not be
enforceable during an EEA event where the EEA process requires the use of Contingency Reserve to
maintain load service. Instead, the Reliability Coordinator, Transmission Operators, and the impacted
Balancing Authorities should use real-time situational awareness, taking into account issues addressed in
BAL-001, BAL-003, the IRO suite of standards and the TOP suite of standards, to determine what actions
are appropriate when conditions are abnormal. This process would allow continued load service without
arbitrarily requiring the interruption of firm load (i.e., shedding load) absent any significant risks to
reliability. See BAL-002 Background Document (July 2015) at 27, available at:
http://www.nerc.com/pa/Stand/Project%202010141%20%20Phase%201%20of%20Balancing%20Author
ity%20Re/BAL-002-2_Background_Document_Redline_09292015.pdf

34

VI.

CONCLUSION
For the reasons set forth above, NERC respectfully requests that the Commission approve (i)

proposed Reliability Standard BAL-002-2 (Exhibit C), and NERC Glossary definitions included
in Exhibit D; (ii) the Implementation Plan in Exhibit D; (iii) the VRFs and VSLs in Exhibit G;
and (v) the retirement of currently-effective Reliability Standard BAL-002-1 and the existing
definition of Contingency Reserve.

Respectfully submitted,
/s/ Andrew C. Wills
Holly A. Hawkins
Associate General 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]

Counsel for the North American Electric
Reliability Corporation
Date: January 29, 2016

35

Exhibit A
Examples of Reportable Balancing Contingency Events

Examples of Reportable Balancing Contingency Events
The proposed definition for Reportable Balancing Contingency Event (“RCBE”) is
“Any Balancing Contingency Event occurring within a one-minute interval of an initial
sudden decline in ACE based on EMS scan rate data that results in a loss of MW output less
than or equal to the Most Severe Single Contingency, and greater than or equal to the lesser
amount of: (i) 80% of the Most Severe Single Contingency, or (ii) the amount listed below
for the applicable Interconnection. Prior to any given calendar quarter, the 80% threshold
may be reduced by the responsible entity upon written notification to the Regional Entity.
• Eastern Interconnection – 900 MW
• Western Interconnection – 500 MW
• ERCOT – 800 MW
• Quebec – 500 MW”
Given this proposed definition, the following table shows examples of unit losses and whether
these losses would be considered a RCBE for purposes of assessing an entity’s responsibilities
under Requirement R1 if an entity in the Eastern Interconnection has a 1,000 MW Most Severe
Single Contingency. The first column explains the proposed unit or units lost, the middle column
confirms whether the loss is an RCBE, and the third column explains the reason for the RCBE
determination and whether this determination affects the Contingency Event Recovery Period.
Loss

RBCE?

Reasoning

750 MW Unit

No

The loss is less than 80 percent of the entity’s
MSSC.

Yes

The loss is less than the MSSC but is greater than
80 percent of the entity’s MSSC. Measurement of
the Contingency Event Recovery Period starts
from the time of the loss of the unit and extends
out 15 minutes.

Yes

The loss is equal to the MSSC and is greater than
80 percent of the entity’s MSSC. Measurement of
the Contingency Event Recovery Period starts
from the time of the loss of the unit and extends
out 15 minutes.

850 MW Unit

1,000 MW unit

750 MW unit and
200 MW Unit
within 60 seconds

Yes

The total loss from the two events, which are
aggregated because both events occurred within
one minute of each other, is less than the MSSC
but is greater than 80 percent of the MSSC.
Measurement of the Contingency Event
Recovery Period begins at the time of the loss of
the 750 MW unit and extends out 15 minutes.

750 MW unit and
then a 300 MW
unit within 60
seconds
750 MW unit loss
and then 200 MW
unit loss 90
seconds later
750 MW unit loss
and then 300 MW
unit loss 90
seconds later

No

The total loss from the two events, which are
aggregated because both events occurred within
one minute of each other, is greater than the
entity’s MSSC.

No

The two events do not occur within 60 seconds of
each other, so this would be two separate
Balancing Contingency Events, neither of which
are an RCBE.

No

The two events do not occur within 60 seconds of
each other, so this would be two separate
Balancing Contingency Events, neither of which
are an RCBE.
The loss of the 850 MW unit is an RCBE because
total loss of resources is equal to the entity’s
MSSC.

850 MW unit loss
and then 150 MW
unit loss 90
seconds later

Yes (850 MW) No
(150 MW)

The loss of the 150 MW unit is not combined with
the loss of the 850 MW unit for purposes of
RCBE determination because it occurred after
one minute, and the loss of this unit alone is not
an RCBE; however, because the second event
occurred during the Contingency Event Recovery
Period, the calculation of compliance will be
adjusted for the loss of the second unit (i.e.
assuming the ACE is zero at the time of the first
event, compliance would require an ACE of -150
at the end of the 15 minute recovery period).
The loss of the 1,000 MW unit is equal to the
MSSC and is greater than 80 percent of the
MSSC.

1,000 MW unit
loss then 200
MW unit loss 10
minutes later

Yes (1000 MW) No
(200 MW)
R1.3.2 applies

The loss of the 200 MW unit is within the
Contingency Reserve Recovery Period and is not
an RCBE.
Total loss of generation from both events is
greater than the entity’s MSSC and is within the
Contingency Reserve Recovery Period, so under
R1.3.2, the entity does not have to restore the
Reporting ACE to defined values within the
original Contingency Event Recovery Period
under R1.1.

The loss of the 900 MW unit is an RCBE because
it is less than the MSSC but greater than 80
percent of the MSSC. No other generation is lost
within the 15 minute Contingency Reserve
Recovery Period.

900 MW unit loss
then 200 MW
unit loss 16
minutes later

Yes (900 MW) No
(200 MW)
R3 applies
R1.3.2 applies

The loss of the 200 MW unit is after the
Contingency Reserve Recovery Period and is not
an RCBE.
However, the loss of the 200 MW unit is within
the Contingency Reserve Restoration Period, and
when combined with the 900 MW unit loss, the
loss is greater than the MSSC. Under R1.3.2, the
entity does not have to restore the Reporting ACE
within the Contingency Event Recovery Period
under R1.1. Under R3, the Contingency Reserve
Recovery Period is reset, and reserves would have
to be recovered within 105 minutes from the
second event.

Exhibit B
Calculating Most Severe Single Contingency

Calculating Most Severe Single Contingency
The Most Severe Single Contingency (“MSSC”) for a Responsible Entity is dynamic in nature and
is associated with an event due to a single contingency “that would result in the greatest loss
(measured in MW) of resource output” used by the Responsible Entity at the time of the event to
meet Firm Demand and export obligation (excluding export obligations for which Contingency
Reserve obligations are being met by the Sink Balancing Authority).
A single contingency could be one of the following events:
•
•
•

A single line-to-ground or three-phase fault (whichever is more sever), with normal
clearing, on any faulted generator, line, transformer, or shunt device; or
Loss of any generator, line, transformer, or shut device without a fault; or
A single pole block, with normal clearing, in a monopole or bipole high-voltage direct
current system.

To effectively recover from an event or series of events and to meet obligations imposed by
relevant requirements, a Responsible Entity should be aware of all of the above single
contingencies, and applicable variations thereof, that would cause a resource output (in MW). For
example, the MSSC may be the loss of a single generator, or the loss of multiple generators if all
of the generators were connected to a common point. In another scenario, a step-up gathering
transformer for a wind farm may be the MSSC. Further, if the loss of a transmission line is caused
by one of the above single contingency events, this single lost transmission line transferring MWs
to the BA may be the entity’s MSSC.
All events that are considered single contingencies must result in a sudden loss of resource output
and cause an instantaneous and unexpected change to the Responsible Entities Area Control Error.
All single contingencies should be evaluated based upon the above criteria to determine if the
Responsible Entity loses resource output. The determination of the Responsible Entity’s MSSC
is driven by the possibility of a physical event, and it is not an economic issue. Responsible Entities
are compelled and highly motivated to determine the MSSC correctly since it allows them to
maintain reliability and to be consistent and compliant with other NERC Reliability Standards
such as BAL-001 and various TPL Standards. 1
The following example scenarios, provided as illustration only, highlight the fact that the MSSC
is generally dynamic because it depends on the output of a specific unit [or units] or the value of a
firm import [or imports].

1

The standard drafting team for Project 2010-14.1 also notes that if the MSSC is too small and it is regularly
exceeded, the entity will still have to regularly gamble on recovering ACE to meet BAAL. This "gaming"
will likely result in a future violation. In addition, the Responsible Entities will come under scrutiny from their
neighbors and may no longer be in compliance with BAL-002-2 or other standards.

Scenario 1
Suppose a Balancing Authority has one or more large units with the same rating, such as super
critical coals units (1100 plus MW). Assuming these large units are the largest units on the system
and one or more of these units will always be online, the output of one of these units may be MSSC
for that Balancing Authority (notably, if one or more of these units are full output units, this MSSC
may also be fixed for the year).
However, suppose that there is a hydro unit that is attached to the auxiliary buss of one of the super
critical coal units described above, and the hydro unit will trip at the same time as the very large
unit. In this case, the MSSC would be the output of the super critical coal unit plus the output of
the hydro unit, thus making a dynamic MSSC.
Scenario 2
As illustrated by this scenario and Scenario 3, an entity’s MSSC may be tied to the value of
output traveling on a transmission line.
Suppose a Balancing Authority had a single high capacity transmission line, which is the only tie
line to a neighboring Balancing Authority. If the neighboring Balancing Authority is the source
of large firm import and the import would be cut as a result of the loss of the transmission, the firm
import from this high capacity transmission line may be the MSSC. In this case, a Balancing
Authority may choose to limit the firm import to some size to keep the MSSC at a value which is
recoverable.
Scenario 3
Suppose a BA had several large hydro units tied to single line because of the remoteness of
the facility. In this case, the MSSC may be the total output of those plants.
Scenario 4
Suppose a Balancing Authority has more than one large unit at a single site with a high reliability
scheme, such as a breaker-an-a-half scheme and bus tie breakers, with many high capacity lines
leaving the site. In this case, the total of the units would not be the MSSC for the Balancing
Authority, because for all of the units to trip at one time would require a black hole scenario. 2

2

The drafting team for Project 2010-14.1 notes that, for purposes of planning for compliance with TPL-001-4, an
entity’s MSSC would likely be the loss associated with the P1 contingencies; however, the team recognizes that
circumstances may dictate different results.

Exhibit C
Proposed Reliability Standard BAL-002-2

BAL-002-2 Clean Version

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
A. Introduction
1.

Title: Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event

2.

Number:

3.

Purpose: To ensure the Balancing Authority or Reserve Sharing Group balances
resources and demand and returns the Balancing Authority's or Reserve Sharing
Group's Area Control Error to defined values (subject to applicable limits) following a
Reportable Balancing Contingency Event.

4.

Applicability:
4.1.

BAL-002-2

Responsible Entity
4.1.1. Balancing Authority
4.1.1.1.
A Balancing Authority that is a member of a Reserve
Sharing Group is the Responsible Entity only in periods during which the
Balancing Authority is not in active status under the applicable
agreement or governing rules for the Reserve Sharing Group.
4.1.2. Reserve Sharing Group

5.

Effective Date: See the Implementation Plan for BAL-002-2.

6.

Background:
Reliably balancing an Interconnection requires frequency management and all of its
aspects. Inputs to frequency management include Tie-Line Bias Control, Area Control
Error (ACE), and the various Requirements in NERC Resource and Demand Balancing
Standards, specifically BAL-001-2 Real Power Balancing Control Performance and BAL003-1 Frequency Response and Frequency Bias Setting.

B. Requirements and Measures
R1.

The Responsible Entity experiencing a Reportable Balancing Contingency Event shall:
[Violation Risk Factor: Medium] [Time Horizon: Real-time Operations]
1.1.

within the Contingency Event Recovery Period, demonstrate recovery by
returning its Reporting ACE to at least the recovery value of:
•

zero (if its Pre-Reporting Contingency Event ACE Value was positive or
equal to zero); however, any Balancing Contingency Event that occurs
during the Contingency Event Recovery Period shall reduce the required
recovery: (i) beginning at the time of, and (ii) by the magnitude of, such
individual Balancing Contingency Event,

or,
•

its Pre-Reporting Contingency Event ACE Value (if its Pre-Reporting
Contingency Event ACE Value was negative); however, any Balancing

Page 1 of 9

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
Contingency Event that occurs during the Contingency Event Recovery
Period shall reduce the required recovery: (i) beginning at the time of, and
(ii) by the magnitude of, such individual Balancing Contingency Event.
1.2.

document all Reportable Balancing Contingency Events using CR Form 1.

1.3.

deploy Contingency Reserve, within system constraints, to respond to all
Reportable Balancing Contingency Events, however, it is not subject to
compliance with Requirement R1 part 1.1 if:
1.3.1 the Responsible Entity:
•

is a Balancing Authority experiencing a Reliability Coordinator
declared Energy Emergency Alert Level or is a Reserve Sharing Group
whose member, or members, are experiencing a Reliability
Coordinator declared Energy Emergency Alert level, and

•

is utilizing its Contingency Reserve to mitigate an operating
emergency in accordance with its emergency Operating Plan, and

•

has depleted its Contingency Reserve to a level below its Most Severe
Single Contingency

or,
1.3.2 the Responsible Entity experiences:
•

multiple Contingencies where the combined MW loss exceeds its
Most Severe Single Contingency and that are defined as a single
Balancing Contingency Event, or

•

multiple Balancing Contingency Events within the sum of the time
periods defined by the Contingency Event Recovery Period and
Contingency Reserve Restoration Period whose combined magnitude
exceeds the Responsible Entity's Most Severe Single Contingency.

M1. Each Responsible Entity shall have, and provide upon request, as evidence, a CR Form
1 with date and time of occurrence to show compliance with Requirement R1. If
Requirement R1 part 1.3 applies, then dated documentation that demonstrates
compliance with Requirement R1 part 1.3 must also be provided.
R2. Each Responsible Entity shall develop, review and maintain annually, and implement
an Operating Process as part of its Operating Plan to determine its Most Severe Single
Contingency and make preparations to have Contingency Reserve equal to, or greater
than the Responsible Entity’s Most Severe Single Contingency available for
maintaining system reliability. [Violation Risk Factor: Medium] [Time Horizon:
Operations Planning]

Page 2 of 9

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
M2. Each Responsible Entity will have the following documentation to show compliance
with Requirement R2:
•

a dated Operating Process;

•

evidence to indicate that the Operating Process has been reviewed and
maintained annually; and,

•

evidence such as Operating Plans or other operator documentation that
demonstrate that the entity determines its Most Severe Single Contingency and
that Contingency Reserves equal to or greater than its Most Severe Single
Contingency are included in this process.

R3. Each Responsible Entity, following a Reportable Balancing Contingency Event, shall
restore its Contingency Reserve to at least its Most Severe Single Contingency, before
the end of the Contingency Reserve Restoration Period, but any Balancing
Contingency Event that occurs before the end of a Contingency Reserve Restoration
Period resets the beginning of the Contingency Event Recovery Period. [Violation Risk
Factor: Medium] [Time Horizon: Real-time Operations]
M3. Each Responsible Entity will have documentation demonstrating its Contingency
Reserve was restored within the Contingency Reserve Restoration Period, such as
historical data, computer logs or operator logs.
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 full-time period
since the last audit.
The Responsible Entity shall retain data or evidence to show compliance for the
current year, plus three previous calendar years, unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer
period of time as part of an investigation.

Page 3 of 9

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event
If a Responsible Entity is found noncompliant, it shall keep information related
to the noncompliance until found compliant, or for the time period specified
above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
subsequent requested and submitted records.
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
The Responsible Entity may use Contingency Reserve for any Balancing
Contingency Event and as required for any other applicable standards.

Page 4 of 9

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event
Table of Compliance Elements
R#

Time
Horizon

VRF

Violation Severity Levels
Lower VSL

R1.

Real-time
Operations

Medium The Responsible Entity
achieved less than
100% but at least 90%
of required recovery
from a Reportable
Balancing Contingency
Event during the
Contingency Event
Recovery Period

Moderate VSL

High VSL

Severe VSL

The Responsible Entity
achieved less than
90% but at least 80%
of required recovery
from a Reportable
Balancing Contingency
Event during the
Contingency Event
Recovery Period.

The Responsible Entity
achieved less than
80% but at least 70%
of required recovery
from a Reportable
Balancing Contingency
Event during the
Contingency Event
Recovery Period.

The Responsible Entity
achieved less than
70% of required
recovery from a
Reportable Balancing
Contingency Event
during the
Contingency Event
Recovery Period.

N/A

The Responsible Entity
developed an
Operating Process to
determine its Most
Severe Single
Contingency and to
have Contingency
Reserve equal to, or
greater than the

The Responsible Entity
failed to develop an
Operating Process to
determine its Most
Severe Single
Contingency and to
have Contingency
Reserve equal to, or
greater than the

OR
The Responsible Entity
failed to use CR Form 1
to document a
Reportable Balancing
Contingency Event.
R2.

Operations
Planning

Medium The Responsible Entity
developed and
implemented an
Operating Process to
determine its Most
Severe Single
Contingency and to
have Contingency
Reserve equal to, or

Page 5 of 9

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event
greater than the
Responsible Entity’s
Most Severe Single
Contingency but failed
to maintain annually
the Operating Process.
R3

Real-time
Operations

Medium The Responsible Entity
restored less than
100% but at least 90%
of required
Contingency Reserve
following a Reportable
Balancing Contingency
Event during the
Contingency Event
Restoration Period.

The Responsible Entity
restored less than 90%
but at least 80% of
required Contingency
Reserve following a
Reportable Balancing
Contingency Event
during the
Contingency Event
Restoration Period.

Responsible Entity’s
Most Severe Single
Contingency but failed
to implement the
Operating Process.

Responsible Entity’s
Most Severe Single
Contingency..

The Responsible Entity
restored less than 80%
but at least 70% of
required Contingency
Reserve following a
Reportable Balancing
Contingency Event
during the
Contingency Event
Restoration Period.

The Responsible Entity
restored less than 70%
of required
Contingency Reserve
following a Reportable
Balancing Contingency
Event during the
Contingency Event
Restoration Period.

D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event Background Document
CR Form 1

Page 6 of 9

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0

August 8, 2005

Removed “Proposed” from
Effective Date

Errata

0

February 14,
2006

Revised graph on page 3, “10
min.” to “Recovery time.”
Removed fourth bullet.

Errata

1

September 9,
2010

Filed petition for revisions to BAL002 Version 1 with the
Commission

Revision

1

January 10, 2011

FERC letter ordered in Docket No.
RD10-15-00 approving BAL-002-1

1

April 1, 2012

Effective Date of BAL-002-1

1a

November 7,
2012

Interpretation adopted by the
NERC Board of Trustees

1a

February 12,
2013

Interpretation submitted to FERC

2

November 5,
2015

Adopted by NERC Board of
Trustees

Complete revision

Page 7 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 BOT adoption, the text from the rationale
text boxes was moved to this section.
Rationale for Requirement R1:
Requirement R1 reflects the operating principles first established by NERC Policy 1 (Generation
Control and Performance). Its objective is to assure the Responsible Entity balances resources
and demand and returns its Reporting Area Control Error (ACE) to defined values (subject to
applicable limits) following a Reportable Balancing Contingency Event. It requires the
Responsible Entity to recover from events that would be less than or equal to the Responsible
Entity’s MSSC. It establishes the amount of Contingency Reserve and recovery and restoration
timeframes the Responsible Entity must demonstrate in a compliance evaluation. It is intended
to eliminate the ambiguities and questions associated with the existing standard. In addition, it
allows Responsible Entities to have a clear way to demonstrate compliance and support the
Interconnection to the full extent of its MSSC.
Requirement R1 does not apply when an entity experiences a Balancing Contingency Event that
exceeds its MSSC (which includes multiple Balancing Contingency Events as described in R1 part
1.3.2 below) because a fundamental goal of the SDT is to assure the Responsible Entity has
enough flexibility to maintain service to Demand while managing reliability. The SDT’s intent is
to eliminate any potential overlap or conflict with any other NERC Reliability Standard to
eliminate duplicative reporting, and other issues.
Commenters suggested a Quarterly Compliance similar to the current reports sent to NERC. The
drafting team attempted to draft measurement language and VSL’s for quarterly monitoring of
compliance to R1. But the drafting team found that the VSL levels developed were likely to
place smaller BA’s and RSGs in a severe violation regardless of the size of the failure. Therefore,
the drafting team has not adopted a quarterly compliance calculation. Also, the proposed
requirement and compliance process meets the directive in Paragraph 354 of Order 693.
Finally, commenters have suggested that the language in R1 part 1.3 be changed to specifically
state under which EEA level the exclusion applies. The drafting team disagrees with this
proposal. NERC is in the process of changing the EEA levels and what is expected in each level.
The current EEA levels suggest that when an entity is experiencing an EEA Level 2 or 3 it is short
of Contingency Reserves as normally defined to exclude readiness to curtail a specific amount
of Firm Demand. Under the proposed EEA process, this would only be during an EEA Level 3. In
order to reduce the need for consequent modifications of the BAL-002 standard, the drafting
team has developed the proposed language in Requirement 1 Part 1.3.1 such that it addresses
both current and future EEA process. In addition, the drafting team has added some clarifying
language to 1.3.1 since comments were presented in previous postings expressing a concern
only a Balancing Authority may request declaration of an EEA and a RSG cannot request an EEA.
The standard drafting team’s intent has always been if a BA is experiencing an EEA event under

Page 8 of 9

Supplemental Material
which its contingency reserve has been activated, the RSG in which it resides would also be
considered to be exempt from R1 compliance.
Rationale for Requirement R2:
R2 establishes the need to actively plan in the near term (e.g., day-ahead) for expected
Reportable Balancing Contingency Events. This requirement is similar to the current standard
which requires an entity to have available a level of contingency reserves equal to or greater
than its Most Severe Single Contingency.
Rationale for Requirement R3:
This requirement is similar to the existing requirement that an entity that has experienced an
event shall restore its Contingency Reserves within 105 minutes of the event. Note that if an
entity is experiencing an EEA it may need to depend on potential availability (or make ready for
potential curtailment) of its firm loads to restore Contingency Reserve. This is the reason for the
changes to the definition of Contingency Reserve in the posting.

Page 9 of 9

BAL-002-2 Redline Version

Standard BAL-002-1 — Disturbance Control Performance BAL-002-2 – Disturbance Control

Standard – Contingency Reserve for Recovery from a Balancing Contingency Event
A. Introduction
1.

Title:

2.

Number: BAL-002-1

1.

Purpose: The purpose of the Disturbance Control Standard (DCS) is to–
Contingency Reserve for Recovery from a Balancing Contingency Event

2.

Number:

3.

Purpose: To ensure the Balancing Authority is able to utilize its Contingencyor
Reserve to balanceSharing Group balances resources and demand and return
Interconnection frequency within returns the Balancing Authority's or Reserve Sharing
Group's Area Control Error to defined values (subject to applicable limits) following a
Reportable Disturbance. Because generator failures are far more common than
significant losses of load and because Contingency Reserve activation does not
typically apply to the loss of load, the application of DCS is limited to the loss of
supply and does not apply to the loss of loadBalancing Contingency Event.

4.

Applicability:
4.1. Balancing Authorities
4.2. Reserve Sharing Groups (Balancing Authorities may meet the requirements of
Standard 002 through participation in a Reserve Sharing Group.)
4.3. Regional Reliability Organizations

5.

B.

Disturbance Control Performance

BAL-002-2

(Proposed) Effective Date:
The first day of the first calendar quarter, one year
after applicable regulatory approval; or in those jurisdictions where no regulatory
approval is required, the first day of the first calendar quarter one year after Board of
Trustees’ adoption.

Requirements
R1. Each Balancing Authority shall have access to and/or operate Contingency Reserve to

respond to Disturbances. Contingency Reserve may be supplied from generation,
controllable load resources, or coordinated adjustments to Interchange Schedules.
4.1.

Responsible Entity
4.1.1. Balancing Authority
4.1.1.1.
A Balancing Authority may elect to fulfill its Contingency
Reserve obligations by participating as a that is a member of a Reserve
Sharing Group. In such cases, the is the Responsible Entity only in
periods during which the Balancing Authority is not in active status under
the applicable agreement or governing rules for the Reserve Sharing
Group.
4.1.2. Reserve Sharing Group shall have

5.

Effective Date: See the same responsibilitiesImplementation Plan for BAL-002-2.

Adopted by Board of Trustees: August 5,
2010

5
Page 1 of 14

Standard BAL-002-1 — Disturbance Control Performance BAL-002-2 – Disturbance Control

Standard – Contingency Reserve for Recovery from a Balancing Contingency Event
6.

Background:
Reliably balancing an Interconnection requires frequency management and
obligations as eachall of its aspects. Inputs to frequency management include Tie-Line
Bias Control, Area Control Error (ACE), and the various Requirements in NERC
Resource and Demand Balancing Standards, specifically BAL-001-2 Real Power
Balancing Authority with respect to monitoring and meetingControl Performance and
BAL-003-1 Frequency Response and Frequency Bias Setting.

B. Requirements and Measures
R1.

The Responsible Entity experiencing a Reportable Balancing Contingency Event shall:
[Violation Risk Factor: Medium] [Time Horizon: Real-time Operations]
R1.1.1.1.

within the requirements of Standard BAL-002.Contingency Event
Recovery Period, demonstrate recovery by returning its Reporting ACE to at
least the recovery value of:

R2. Each Regional Reliability Organization, sub-Regional Reliability Organization or

Reserve Sharing Group shall specify its Contingency Reserve policies, including:
R2.1. The minimum reserve requirement for the group.
R2.2. Its allocation among members.

•

The permissible mix ofzero (if its Pre-Reporting Contingency Event ACE
Value was positive or equal to zero); however, any Balancing Contingency
Event that occurs during the Contingency Event Recovery Period shall
reduce the required recovery: (i) beginning at the time of, and (ii) by the
magnitude of, such individual Balancing Contingency Event,

or,
•

its Pre-Reporting Contingency Event ACE Value (if its Pre-Reporting
Contingency Event ACE Value was negative); however, any Balancing
Contingency Event that occurs during the Contingency Event Recovery
Period shall reduce the required recovery: (i) beginning at the time of, and
(ii) by the magnitude of, such individual Balancing Contingency Event.

1.2.

document all Reportable Balancing Contingency Events using CR Form 1.

1.3.

deploy Contingency Reserve, within system constraints, to respond to all
Reportable Balancing Contingency Events, however, it is not subject to
compliance with Requirement R1 part 1.1 if:
1.3.1 the Responsible Entity:
•

is a Balancing Authority experiencing a Reliability Coordinator
declared Energy Emergency Alert Level or is a Reserve Sharing Group
whose member, or members, are experiencing a Reliability
Coordinator declared Energy Emergency Alert level, and

Adopted by Board of Trustees: August 5,
2010

5
Page 2 of 14

Standard BAL-002-1 — Disturbance Control Performance BAL-002-2 – Disturbance Control

Standard – Contingency Reserve for Recovery from a Balancing Contingency Event
•

is utilizing its Contingency Reserve to mitigate an operating
emergency in accordance with its emergency Operating Reserve –
Spinning and Plan, and

•

has depleted its Contingency Reserve to a level below its Most Severe
Single Contingency

or,
1.3.2 the Responsible Entity experiences:
•

multiple Contingencies where the combined MW loss exceeds its
Most Severe Single Contingency and that are defined as a single
Balancing Contingency Event, or

•

multiple Balancing Contingency Events within the sum of the time
periods defined by the Contingency Event Recovery Period and
Contingency Reserve Restoration Period whose combined magnitude
exceeds the Responsible Entity's Most Severe Single Contingency.

M1. Each Responsible Entity shall have, and provide upon request, as evidence, a CR Form
1 with date and time of occurrence to show compliance with Requirement R1. If
Requirement R1 part 1.3 applies, then dated documentation that demonstrates
compliance with Requirement R1 part 1.3 must also be provided.
R2. Each Responsible Entity shall develop, review and maintain annually, and implement
an Operating Process as part of its Operating Plan to determine its Most Severe Single
Contingency and make preparations to have Contingency Reserve equal to, or greater
than the Responsible Entity’s Most Severe Single Contingency available for
maintaining system reliability. [Violation Risk Factor: Medium] [Time Horizon:
Operations Planning]
M2. Each Reserve – Supplemental that may beResponsible Entity will have the following
documentation to show compliance with Requirement R2:
•

a dated Operating Process;

•

evidence to indicate that the Operating Process has been reviewed and
maintained annually; and,

•

evidence such as Operating Plans or other operator documentation that
demonstrate that the entity determines its Most Severe Single Contingency and
that Contingency Reserves equal to or greater than its Most Severe Single
Contingency are included in this process.

R2.3.R3.

Each Responsible Entity, following a Reportable Balancing Contingency Event,
shall restore its Contingency Reserve to at least its Most Severe Single Contingency,
before the end of the Contingency Reserve Restoration Period, but any Balancing
Contingency Event that occurs before the end of a Contingency Reserve. Restoration

Adopted by Board of Trustees: August 5,
2010

5
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Standard BAL-002-1 — Disturbance Control Performance BAL-002-2 – Disturbance Control

Standard – Contingency Reserve for Recovery from a Balancing Contingency Event
Period resets the beginning of the Contingency Event Recovery Period. [Violation Risk
Factor: Medium] [Time Horizon: Real-time Operations]
Each Responsible Entity will have
documentation demonstrating its Contingency Reserve in practice.

R2.4. The procedure for applyingM3.

R2.5. The limitations, if any, upon the amount of interruptible load that may be

included.
The same portion of resource capacity (e.g. reserves from jointly
owned generation) shall not be counted more than once as Contingency
Reserve by multiple Balancing Authorities.was restored
R2.6.

R3. Each Balancing Authority or Reserve Sharing Group shall activate sufficient

Contingency Reserve to comply with the DCS.
R3.1. As a minimum, the Balancing Authority or Reserve Sharing Group shall carry

at least enough Contingency Reserve to cover the most severe single
contingency. All Balancing Authorities and Reserve Sharing Groups shall
review, no less frequently than annually, their probable contingencies to
determine their prospective most severe single contingencies.
R4. A Balancing Authority or Reserve Sharing Group shall meet the Disturbance

Recovery Criterion within the Disturbance Recovery Period for 100% of Reportable
Disturbances. The Disturbance Recovery Criterion is:
R4.1. A Balancing Authority shall return its ACE to zero if its ACE just prior to the

Reportable Disturbance was positive or equal to zero. For negative initial ACE
values just prior to the Disturbance, the Balancing Authority shall return ACE
to its pre-Disturbance value.
R4.2. The default Disturbance Recovery Period is 15 minutes after the start of a

Reportable Disturbance.
R5. Each Reserve Sharing Group shall comply with the DCS. A Reserve Sharing Group

shall be considered in a Reportable Disturbance condition whenever a group member
has experienced a Reportable Disturbance and calls for the activation of Contingency
Reserves from one or more other group members. (If a group member has
experienced a Reportable Disturbance but does not call for reserve activation from
other members of the Reserve Sharing Group, then that member shall report as a
single Balancing Authority.) Compliance may be demonstrated by either of the
following two methods:
R5.1. The Reserve Sharing Group reviews group ACE (or equivalent) and

demonstrates compliance to the DCS. To be in compliance, the group ACE (or
its equivalent) must meet the Disturbance Recovery Criterion after the schedule
change(s) related to reserve sharing have been fully implemented, and within
the Disturbance Recovery Period.
or
R5.2. The Reserve Sharing Group reviews each member’s ACE in response to the

activation of reserves. To be in compliance, a member’s ACE (or its
Adopted by Board of Trustees: August 5,
2010

5
Page 4 of 14

Standard BAL-002-1 — Disturbance Control Performance BAL-002-2 – Disturbance Control

Standard – Contingency Reserve for Recovery from a Balancing Contingency Event
equivalent) must meet the Disturbance Recovery Criterion after the schedule
change(s) related to reserve sharing have been fully implemented, and within
the Disturbance Recovery Period.
R6. A Balancing Authority or Reserve Sharing Group shall fully restore its Contingency

Reserves within the Contingency Reserve Restoration Period for its Interconnection.
R6.1. The Contingency Reserve Restoration Period begins at the end of the

Disturbance Recovery Period.
R6.2. The default Contingency Reserve Restoration Period is 90 minutes.
C.

Measures
M1. A Balancing Authority or Reserve Sharing Group shall calculate and report compliance
with the Disturbance Control Standard for all Disturbances greater than or equal to 80%
of the magnitude of the Balancing Authority’s or of the Reserve Sharing Group’s most
severe single contingency loss. Regions may, at their discretion, require a lower
reporting threshold. Disturbance Control Standard is measured, such as the percentage
recovery (Ri).historical data, computer logs or operator logs.
For loss of generation:
if ACEA < 0
then
MWLoss − max(0, ACE A − ACEM )
Ri =
* 100%
MWLoss

if ACEA > 0
then
Ri =

MW Loss − max(0,− ACE M )
* 100%
MW Loss

where:
• MWLOSS is the MW size of the Disturbance
as measured at the beginning of the loss,
• ACEA is the pre-disturbance ACE,
• ACEM is the maximum algebraic value of ACE measured within the fifteen
minutes following the Disturbance. A Balancing Authority or Reserve Sharing
Group may, at its discretion, set ACEM = ACE15 min, and
The Balancing Authority or Reserve Sharing Group shall record the MWLOSS value as
measured at the site of the loss to the extent possible. The value should not be
Adopted by Board of Trustees: August 5,
2010

5
Page 5 of 14

Standard BAL-002-1 — Disturbance Control Performance BAL-002-2 – Disturbance Control

Standard – Contingency Reserve for Recovery from a Balancing Contingency Event

measured as a change in ACE since governor response and AGC response may
introduce error.
The Balancing Authority or Reserve Sharing Group shall base the value for ACEA on
the average ACE over the period just prior to the start of the Disturbance (10 and 60
seconds prior and including at least 4 scans of ACE). In the illustration below, the
horizontal line represents an averaging of ACE for 15 seconds prior to the start of the
Disturbance with a result of ACEA = - 25 MW.

ACE
-30

-20

-10

0

0

-40

-80

D.C.

1.

The average percent recovery is the arithmetic average of all the calculated Ri’s for
Reportable Disturbances during a given quarter. Average percent recovery is similarly
calculated for excludable Disturbances.
Compliance
Compliance Monitoring Process

Compliance with the DCS shall be measured on a percentage basis as set forth in the
measures above.
Each Balancing Authority or Reserve Sharing Group shall submit one completed copy
of DCS Form, “NERC Control Performance Standard Survey – All Interconnections”
to its Resources Subcommittee Survey Contact no later than the 10th day following
the end of the calendar quarter (i.e. April 10th, July 10th, October 10th, January 10th).
Adopted by Board of Trustees: August 5,
2010

5
Page 6 of 14

Standard BAL-002-1 — Disturbance Control Performance BAL-002-2 – Disturbance Control

Standard – Contingency Reserve for Recovery from a Balancing Contingency Event

The Regional Entity must submit a summary document reporting compliance with
DCS to NERC no later than the 20th day of the month following the end of the quarter.
1.1.

Compliance Enforcement Authority
Regional Entity.
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 full-time period
since the last audit.
The Responsible Entity shall retain data or evidence to show compliance for the
current year, plus three previous calendar years, unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer
period of time as part of an investigation.
If a Responsible Entity is found noncompliant, it shall keep information related
to the noncompliance until found compliant, or for the time period specified
above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
subsequent requested and submitted records.

1.2.1.3.

Compliance Monitoring Period and Reset TimeframeAssessment
Processes:
Compliance for DCS will be evaluated for each reporting period. Reset is one
calendar quarter without a violation.

1.3.

As defined in the NERC Rules of Procedure, “Compliance Monitoring and
EnforcementAssessment Processes:

Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.4.

Data Retention
The data that support the calculation of DCS are” refers to be retained in
electronic form for at least a one-year period. If the DCS data for a Reserve

Adopted by Board of Trustees: August 5,
2010

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Page 7 of 14

Standard BAL-002-1 — Disturbance Control Performance BAL-002-2 – Disturbance Control

Standard – Contingency Reserve for Recovery from a Balancing Contingency Event

Sharing Group and Balancing Area are undergoing a review to address a
question that has been raised regardingidentification of the data, processes that
will be used to evaluate data or information for the data are to be saved
beyondpurpose of assessing performance or outcomes with the normal
retention period until the question is formally resolvedassociated Reliability
Standard.
1.5.1.4.

Additional Compliance Information
Reportable Disturbances – Reportable Disturbances are contingencies that are
greater than or equal to 80% of the most severe single Contingency. A
Regional Reliability Organization, sub-Regional Reliability Organization or
Reserve Sharing Group may optionally reduce the 80% threshold, provided that
normal operating characteristics are not being considered or misrepresented as
contingencies. Normal operating characteristics are excluded because DCS
only measures the recovery from sudden, unanticipated losses of supply-side
resources.
Simultaneous Contingencies – Multiple Contingencies occurring within one
minute or less of each other shall be treated as a single Contingency. If the
combined magnitude of the multiple Contingencies exceeds the most severe
single Contingency, the loss shall be reported, but excluded from compliance
evaluation.
Multiple Contingencies within the Reportable Disturbance Period –
Additional Contingencies that occur after one minute of the start of a
Reportable Disturbance but before the end of the Disturbance Recovery Period
can be excluded from evaluation. The Balancing Authority or Reserve Sharing
Group shall determine the DCS compliance of the initial Reportable
Disturbance by performing a reasonable estimation of the response that would
have occurred had the second and subsequent contingencies not occurred.

Multiple Contingencies within the Contingency Reserve Restoration Period
– Additional Reportable Disturbances that occur after the end of the
Disturbance Recovery Period but before the end of the Contingency Reserve
Restoration Period shall be reported and included in the compliance evaluation.
However, the Balancing Authority or Reserve Sharing Group can request a
waiver from the Resources Subcommittee for the event if the contingency
reserves were rendered inadequate by prior contingencies and a good faith
effort to replace contingency reserve can be shown.
Levels of Non-The Responsible Entity may use Contingency Reserve for any
Balancing Contingency Event and as required for any other applicable
standards.

Adopted by Board of Trustees: August 5,
2010

5
Page 8 of 14

Standard BAL-002-1 — Disturbance Control Performance BAL-002-2 – Disturbance Control Standard – Contingency Reserve for

Recovery from a Balancing Contingency Event
Table of Compliance Elements

2.

Each Balancing Authority or Reserve Sharing Group not meeting the DCS during a given calendar quarter shall increase its
Contingency Reserve obligation for the calendar quarter (offset by one month) following the evaluation by the NERC or
Compliance Monitor [e.g. for the first calendar quarter of the year, the penalty is applied for May, June, and July.] The
increase shall be directly proportional to the non-compliance with the DCS in the preceding quarter. This adjustment is not
compounded across quarters, and is an additional percentage of reserve needed beyond the most severe single Contingency.
A Reserve Sharing Group may choose an allocation method for increasing its Contingency Reserve for the Reserve Sharing
Group provided that this increase is fully allocated.
A representative from each Balancing Authority or Reserve Sharing Group that was non-compliant in the calendar quarter
most recently completed shall provide written documentation verifying that the Balancing Authority or Reserve Sharing
Group will apply the appropriate DCS performance adjustment beginning the first day of the succeeding month, and will
continue to apply it for three months. The written documentation shall accompany the quarterly Disturbance Control
Standard Report when a Balancing Authority or Reserve Sharing Group is non-compliant.
3.

R#

Violation Severity Levels (no changes)
Time
Horizon

VRF

Violation Severity Levels
Lower VSL

R1.

Real-time
Operations

Medium The Responsible Entity
achieved less than
100% but at least 90%
of required recovery
from a Reportable
Balancing Contingency
Event during the
Contingency Event
Recovery Period

Moderate VSL

High VSL

Severe VSL

The Responsible Entity
achieved less than
90% but at least 80%
of required recovery
from a Reportable
Balancing Contingency
Event during the
Contingency Event
Recovery Period.

The Responsible Entity
achieved less than
80% but at least 70%
of required recovery
from a Reportable
Balancing Contingency
Event during the
Contingency Event
Recovery Period.

The Responsible Entity
achieved less than
70% of required
recovery from a
Reportable Balancing
Contingency Event
during the
Contingency Event
Recovery Period.

OR
The Responsible Entity
failed to use CR Form 1

5, 2010

Adopted by Board of Trustees: August
9
Page 9 of 14

Standard BAL-002-1 — Disturbance Control Performance BAL-002-2 – Disturbance Control Standard – Contingency Reserve for

Recovery from a Balancing Contingency Event
to document a
Reportable Balancing
Contingency Event.
R2.

Operations
Planning

Medium The Responsible Entity
developed and
implemented an
Operating Process to
determine its Most
Severe Single
Contingency and to
have Contingency
Reserve equal to, or
greater than the
Responsible Entity’s
Most Severe Single
Contingency but failed
to maintain annually
the Operating Process.

N/A

The Responsible Entity
developed an
Operating Process to
determine its Most
Severe Single
Contingency and to
have Contingency
Reserve equal to, or
greater than the
Responsible Entity’s
Most Severe Single
Contingency but failed
to implement the
Operating Process.

The Responsible Entity
failed to develop an
Operating Process to
determine its Most
Severe Single
Contingency and to
have Contingency
Reserve equal to, or
greater than the
Responsible Entity’s
Most Severe Single
Contingency..

R3

Real-time
Operations

Medium The Responsible Entity
restored less than
100% but at least 90%
of required
Contingency Reserve
following a Reportable
Balancing Contingency
Event during the
Contingency Event
Restoration Period.

The Responsible Entity
restored less than 90%
but at least 80% of
required Contingency
Reserve following a
Reportable Balancing
Contingency Event
during the
Contingency Event
Restoration Period.

The Responsible Entity
restored less than 80%
but at least 70% of
required Contingency
Reserve following a
Reportable Balancing
Contingency Event
during the
Contingency Event
Restoration Period.

The Responsible Entity
restored less than 70%
of required
Contingency Reserve
following a Reportable
Balancing Contingency
Event during the
Contingency Event
Restoration Period.

5, 2010

Adopted by Board of Trustees: August
9
Page 10 of 14

Standard BAL-002-1 — Disturbance Control Performance BAL-002-2 – Disturbance Control Standard – Contingency Reserve for

Recovery from a Balancing Contingency Event
E.D.

Regional DifferencesVariances

None identified.
E. Interpretations
None.
F. Associated Documents
BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event Background Document
CR Form 1

5, 2010

Adopted by Board of Trustees: August
9
Page 11 of 14

Standard BAL-002-1 — Disturbance Control Performance BAL-002-2 – Disturbance Control

Standard – Contingency Reserve for Recovery from a Balancing Contingency Event

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0

August 8, 2005

Removed “Proposed” from
Effective Date

Errata

0

February 14,
2006

Revised graph on page 3, “10
min.” to “Recovery time.”
Removed fourth bullet.

Errata

1

September 9,
2010

Filed petition for revisions to BAL002 Version 1 with the
Commission

Revision

1

TBDJanuary 10,
2011

Modified to address Order No. 693 Revised.
Directives contained in paragraph
321.FERC letter ordered in Docket
No. RD10-15-00 approving BAL002-1

1

April 1, 2012

Effective Date of BAL-002-1

1a

November 7,
2012

Interpretation adopted by the
NERC Board of Trustees

1a

February 12,
2013

Interpretation submitted to FERC

2

November 5,
2015

Adopted by NERC Board of
Trustees

Adopted by Board of Trustees: August 5, 2010

Complete revision

12
Page 12 of 14

Standard BAL-002-1 — Disturbance Control PerformanceSupplemental 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 BOT adoption, the text from the rationale
text boxes was moved to this section.
Rationale for Requirement R1:
Requirement R1 reflects the operating principles first established by NERC Policy 1 (Generation
Control and Performance). Its objective is to assure the Responsible Entity balances resources
and demand and returns its Reporting Area Control Error (ACE) to defined values (subject to
applicable limits) following a Reportable Balancing Contingency Event. It requires the
Responsible Entity to recover from events that would be less than or equal to the Responsible
Entity’s MSSC. It establishes the amount of Contingency Reserve and recovery and restoration
timeframes the Responsible Entity must demonstrate in a compliance evaluation. It is intended
to eliminate the ambiguities and questions associated with the existing standard. In addition, it
allows Responsible Entities to have a clear way to demonstrate compliance and support the
Interconnection to the full extent of its MSSC.
Requirement R1 does not apply when an entity experiences a Balancing Contingency Event that
exceeds its MSSC (which includes multiple Balancing Contingency Events as described in R1 part
1.3.2 below) because a fundamental goal of the SDT is to assure the Responsible Entity has
enough flexibility to maintain service to Demand while managing reliability. The SDT’s intent is
to eliminate any potential overlap or conflict with any other NERC Reliability Standard to
eliminate duplicative reporting, and other issues.
Commenters suggested a Quarterly Compliance similar to the current reports sent to NERC. The
drafting team attempted to draft measurement language and VSL’s for quarterly monitoring of
compliance to R1. But the drafting team found that the VSL levels developed were likely to
place smaller BA’s and RSGs in a severe violation regardless of the size of the failure. Therefore,
the drafting team has not adopted a quarterly compliance calculation. Also, the proposed
requirement and compliance process meets the directive in Paragraph 354 of Order 693.
Finally, commenters have suggested that the language in R1 part 1.3 be changed to specifically
state under which EEA level the exclusion applies. The drafting team disagrees with this
proposal. NERC is in the process of changing the EEA levels and what is expected in each level.
The current EEA levels suggest that when an entity is experiencing an EEA Level 2 or 3 it is short
of Contingency Reserves as normally defined to exclude readiness to curtail a specific amount
of Firm Demand. Under the proposed EEA process, this would only be during an EEA Level 3. In
order to reduce the need for consequent modifications of the BAL-002 standard, the drafting
team has developed the proposed language in Requirement 1 Part 1.3.1 such that it addresses
both current and future EEA process. In addition, the drafting team has added some clarifying
language to 1.3.1 since comments were presented in previous postings expressing a concern
only a Balancing Authority may request declaration of an EEA and a RSG cannot request an EEA.
The standard drafting team’s intent has always been if a BA is experiencing an EEA event under
Adopted by Board of Trustees: August 5,
2010

1
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Standard BAL-002-1 — Disturbance Control PerformanceSupplemental Material

which its contingency reserve has been activated, the RSG in which it resides would also be
considered to be exempt from R1 compliance.
Rationale for Requirement R2:
R2 establishes the need to actively plan in the near term (e.g., day-ahead) for expected
Reportable Balancing Contingency Events. This requirement is similar to the current standard
which requires an entity to have available a level of contingency reserves equal to or greater
than its Most Severe Single Contingency.
Rationale for Requirement R3:
This requirement is similar to the existing requirement that an entity that has experienced an
event shall restore its Contingency Reserves within 105 minutes of the event. Note that if an
entity is experiencing an EEA it may need to depend on potential availability (or make ready for
potential curtailment) of its firm loads to restore Contingency Reserve. This is the reason for the
changes to the definition of Contingency Reserve in the posting.

Adopted by Board of Trustees: August 5,
2010

1
Page 14 of 14

Exhibit D
Implementation Plan

Implementation Plan

Project 2010-14.1 Balancing Authority Reliability-based
Controls – Reserves
BAL-002-2

Approvals Required
BAL-002-2 – Disturbance Control Standard - Contingency Reserve for Recovery from a Balancing
Contingency Event
Prerequisite Approvals
None
Revisions to Glossary Terms
The following definitions shall become effective when BAL-002-2 becomes effective:
Balancing Contingency Event: Any single event described in Subsections (A), (B), or (C) below, or
any series of such otherwise single events, with each separated from the next by one minute or
less.
A. Sudden loss of generation:
a. Due to
i. unit tripping, or
ii. loss of generator Facility resulting in isolation of the generator from the Bulk
Electric System or from the responsible entity’s System, or
iii. sudden unplanned outage of transmission Facility;
b. And, that causes an unexpected change to the responsible entity’s ACE;
B. Sudden loss of an Import, due to forced outage of transmission equipment that causes an
unexpected imbalance between generation and Demand on the Interconnection.
C. Sudden restoration of a Demand that was used as a resource that causes an unexpected
change to the responsible entity’s ACE.
Most Severe Single Contingency (MSSC): The Balancing Contingency Event, due to a single
contingency identified using system models maintained within the Reserve Sharing Group (RSG) or
a Balancing Authority’s area that is not part of a Reserve Sharing Group, that would result in the
greatest loss (measured in MW) of resource output used by the RSG or a Balancing Authority that is
not participating as a member of a RSG at the time of the event to meet Firm Demand and export

obligation (excluding export obligation for which Contingency Reserve obligations are being met by
the Sink Balancing Authority).
Reportable Balancing Contingency Event: Any Balancing Contingency Event occurring within a
one-minute interval of an initial sudden decline in ACE based on EMS scan rate data that results in a
loss of MW output less than or equal to the Most Severe Single Contingency, and greater than or
equal to the lesser amount of: (i) 80% of the Most Severe Single Contingency, or (ii) the amount
listed below for the applicable Interconnection. Prior to any given calendar quarter, the 80%
threshold may be reduced by the responsible entity upon written notification to the Regional
Entity.
•

Eastern Interconnection – 900 MW

•

Western Interconnection – 500 MW

•

ERCOT – 800 MW

•

Quebec – 500 MW

Contingency Event Recovery Period: A period that begins at the time that the resource output
begins to decline within the first one-minute interval of a Reportable Balancing Contingency Event,
and extends for fifteen minutes thereafter.
Contingency Reserve Restoration Period: A period not exceeding 90 minutes following the end of
the Contingency Event Recovery Period.
Pre-Reporting Contingency Event ACE Value: The average value of Reporting ACE, or Reserve
Sharing Group Reporting ACE when applicable, in the 16-second interval immediately prior to the
start of the Contingency Event Recovery Period based on EMS scan rate data.
Reserve Sharing Group Reporting ACE: At any given time of measurement for the applicable
Reserve Sharing Group (RSG), the algebraic sum of the ACEs (or equivalent as calculated at such
time of measurement) of the Balancing Authorities participating in the RSG at the time of
measurement.
Contingency Reserve: The provision of capacity that may be deployed by the Balancing Authority to
respond to a Balancing Contingency Event and other contingency requirements (such as Energy
Emergency Alerts as specified in the associated EOP standard). A Balancing Authority may include
in its restoration of Contingency Reserve readiness to reduce Firm Demand and include it if, and
only if, the Balancing Authority:
•

is experiencing a Reliability Coordinator declared Energy Emergency Alert level, and

BAL-002-2 – Disturbance Control Performance - Contingency Reserve for Recovery from a Balancing Contingency Event

2

•

is utilizing its Contingency Reserve to mitigate an operating emergency in accordance with
its emergency Operating Plan.

Applicable Entities
Balancing Authority1
Reserve Sharing Group
Applicable Facilities
N/A
Conforming Changes to Other Standards
None
Effective Dates
BAL-002-2 shall become effective the first day of the first calendar quarter that is six months after the
date that this standard is approved by applicable 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 six months after the date the
standard is adopted by the NERC Board of Trustees, or as otherwise provided for in that jurisdiction.
Justification
The six-month period for implementation of BAL-002-2 will provide ample time for Balancing
Authorities to make necessary modifications to existing software programs to ensure compliance.
Retirements

A Balancing Authority that is a member of a Reserve Sharing Group is the Responsible Entity only in periods during which
the Balancing Authority is not in active status under the applicable agreement or governing rules for the Reserve Sharing
Group. See Section A.4.1.1.1, BAL-002-2.

1

BAL-002-2 – Disturbance Control Performance - Contingency Reserve for Recovery from a Balancing Contingency Event

3

Reliability Standard BAL-002-1, Disturbance Control Performance shall be retired immediately prior to
the effective date of BAL-002-2 in the particular jurisdiction in which the new standard is becoming
effective.
The existing definition of Contingency Reserve should be retired immediately prior to the effective
date of BAL-002-2, in the particular jurisdiction in which the new standard is becoming effective.

BAL-002-2 – Disturbance Control Performance - Contingency Reserve for Recovery from a Balancing Contingency Event

4

Exhibit E
BAL-002-2 Background Document

BAL-002-2
Background Document
September 2015

BAL‐002‐2 ‐ Background Document 
July 2015 

1 

Table of Contents
Introduction .................................................................................................................................... 3 
Rationale by Requirement .............................................................................................................. 7 
Requirement 1 ............................................................................................................................ 7 
Requirement 2 .......................................................................................................................... 14 
Requirement 3 .......................................................................................................................... 15 

BAL‐002‐2 ‐ Background Document 

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Disturbance Control Performance ‐ Contingency Reserve for Recovery From a Balancing 
Contingency Event Standard Background Document 

Introduction 
The revision to NERC Policy Standards in 1996 created a Disturbance Control Standard (DCS).  It  
replaced B1 [Area Control Error (ACE) must return to zero within 10 minutes following a 
disturbance] and B2 (ACE must start to return to zero in 1 minute following a disturbance) with 
a standard that states: ACE must return to either zero or a pre‐disturbance value of ACE within 
15 minutes following a reportable disturbance.  Balancing Authorities were required to report 
all disturbances equal to or greater than 80% of the Balancing Authority’s Most Severe Single 
Contingency (MSSC). 
BAL‐002 was created to replace portions of Policy 1.  It measures the ability of an applicable 
entity to recover from a reportable event with the deployment of reserve.  The reliable 
operation of the interconnected power system requires that adequate capacity and energy be 
available to maintain scheduled frequency and avoid loss of firm load following loss of 
transmission or generation contingencies.  This capacity (Contingency Reserve) is necessary to 
replace capacity and energy lost due to forced outages of generation or transmission 
equipment.   The design of BAL‐002 and Policy 1 was predicated on the Interconnection’s 
operating under normal conditions, and the requirements of BAL‐002 assured recovery from 
single contingency (N‐1) events. 
This document provides background on the development and implementation of BAL‐002‐2 ‐ 
Contingency Reserve for Recovery from a Balancing Contingency Event.  This document explains 
the rationale and considerations for the requirements and their associated compliance 
information.  BAL‐002‐2 was developed to fulfill the NERC Balancing Authority Controls (Project 
2007‐05) Standard Authorization Request (SAR), which includes the incorporation of the FERC 
Order 693 directives.  The original SAR, approved by the industry, presumes there is presently 
sufficient Contingency Reserve in all the North American Interconnections.  The underlying goal 
of the SAR was to update the standard to make the measurement process more objective and 
to provide information to the Balancing Authority or Reserve Sharing Group, such that the 
parties would better understand the use of Contingency Reserve to balance resources and 
demand following a Reportable Balancing Contingency Event.   
Currently, the existing BAL‐002‐1 standard contains Requirements specific to a Reserve Sharing 
Group which the drafting team believes are commercial in nature and a contractual 
arrangement between the reserve sharing group parties.  BAL‐002‐2 is intended to measure the 
successful deployment of contingency reserve by responsible entities.  Relationships between 
the entities should not be part of the performance requirements, but left up to a commercial 
transaction. 
BAL‐002‐2 ‐ Background Document 

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Disturbance Control Performance ‐ Contingency Reserve for Recovery From a Balancing 
Contingency Event Standard Background Document 

Clarity and specifics are provided with several new definitions.  Additionally, the BAL‐002‐2 
eliminates any question about who is the applicable entity and assures that the applicable 
entity is held responsible for the performance requirement.  The drafting team’s goal was to 
have BAL‐002‐2 be solely a performance standard.   The primary objective of BAL‐002‐2 is to 
ensure that the applicable entity is prepared to balance resources and demand and to return its 
ACE to defined values (subject to applicable limits) following a Reportable Balancing 
Contingency Event. 
As proposed, this standard is not intended to address events greater than a Responsible Entity’s 
Most Severe Single Contingency. These large multi‐unit events, although unlikely, do occur.  
Many interactions occur during these events and Balancing Authorities (BAs) and Reserve 
Sharing Groups must react to these events.  However, requiring a recovery of ACE within a 
specific time period is much too simple a methodology to adequately address all of these 
interactions.  The suite of NERC Standards work together to ensure that the Interconnections 
are operated in a safe and reliable manner.  It is not just one standard, rather it is the 
combination of the BAL‐001‐2 standard (in which R2 requires operation within an ACE 
bandwidth based on interconnection frequency), TOP‐007, and EOP‐002, which collectively 
address issues when large events occur.   


The Balancing Authority ACE Limit (BAAL) in R2 of BAL‐001‐2 looks at Interconnection
frequency to provide the BA a range in which the BA should strive to operate as well as
a 30‐minute period to address instances when the BA is outside of that range.  If an
event larger than the BA’s MSSC occurs, the BAAL will likely change to a much tighter
control limit based on the change in interconnection frequency.  The 30‐minute limit
under the BAAL allows the BA (and its RC) time to quickly evaluate the best course of
action and then react in a reasonable manner.  BAAL also ensures the Responsible Entity
balances resources and demand when events occur of less magnitude than a Reportable
Balancing Contingency.  In addition R1 of BAL‐001‐2 requires the BA to respond to
assure Control Performance Standard 1 (CPS1) is met.  This may prompt the BA to
respond in some circumstances in less than 10 minutes.



The TOP‐007 standard addresses transmission line loading. Members of the BAL‐002‐2
drafting team are aware of instances (typically N‐2 or less) that could cause transmission
overloads if certain units were lost and reserves responded.



Under EOP‐002, if the BA does not believe that it can meet certain parameters, different
rules are implemented.

Because of the potential for significant unintended consequences that could occur under a 
requirement to activate all reserves, the drafting team recommends to the industry that the 
revised BAL‐002‐2 address only events which are planned for (N‐1) and not any loss of 
resource(s) that would exceed MSSC.  Therefore, the definitions and Requirements under BAL‐
002‐2 exclude events greater than the MSSC.  This provides clarity of Requirements, supports 
BAL‐002‐2 ‐ Background Document 

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Disturbance Control Performance ‐ Contingency Reserve for Recovery From a Balancing 
Contingency Event Standard Background Document 
reliable operation of the Bulk Electric System and allows other standards to address events of 
greater magnitude and complexity. 
Within NERC’s State of Reliability Report, ALR2‐5 “Disturbance Control Events Greater Than the 
Most Severe Single Contingency” has been tracked and reported since 2006.  For the period 
2006 to 2011 there were 90 disturbance events that exceeded the MSSC, with the highest in 
any given year being 24 events.  Evaluation of the data illustrates events greater than MSSC 
occur very infrequently, and the drafting team believes their exclusion will not have any 
adverse impact on reliability. 
The metric reports the number of DCS events greater than MSSC, regardless of the size of a 
Balancing Authority or RSG and  of the number of reporting entities within a Regional Entity.  A 
small Balancing Authority or RSG may have a relatively small MSSC. As such, a high number of 
DCS events greater than MSSC may not indicate a reliability problem for the reporting Regional 
Entity, but may indicate an issue for the respective Balancing Authority or RSG. In addition, 
events greater than MSSC may not cause a reliability issue for a BA, RSG or Regional Entity that 
has more stringent standards which require contingency reserve greater than MSSC. 

Background  
Reliably balancing an Interconnection requires frequency management and all of its aspects.  
Inputs to frequency management include Tie‐Line Bias Control, Area Control Error (ACE), and 
the various Requirements in NERC Resource and Demand Balancing Standards, specifically BAL‐
001‐2 Real Power Balancing Control Performance and BAL‐003‐1 Frequency Response and 
Frequency Bias Setting. 
Balancing Contingency Event 
BAL‐002‐2 applies during real‐time operations to ensure the Balancing Authority or Reserve 
Sharing Group balance resources and demand by returning its Area Control Error to defined 
values following a Reportable Balancing Contingency Event.  
The drafting team included a specific definition for a Balancing Contingency Event to eliminate 
any confusion and ambiguity.  The prior version of BAL‐002 was broad and could be interpreted 
in various ways leaving the ability to measure compliance in the eye of the beholder.  Including 
the specific definition allows the Responsible Entity to fully understand how to perform and 
meet compliance.  Also, FERC Order 693 (at P355) directed entities to include a Requirement 
that measures response for any event or contingency that causes a frequency deviation.  By 
developing a specific definition that depicts the events causing an unexpected change to the 
Responsible Entity’s ACE, the necessary response requirements assure the intent of the FERC 
requirement is met. 
BAL‐002‐2 ‐ Background Document 

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Disturbance Control Performance ‐ Contingency Reserve for Recovery From a Balancing 
Contingency Event Standard Background Document 
The definitions of Reportable Balancing Contingency Event and Contingency Event Recovery 
Period work together to specify the timing requirements for recoveries from Reportable 
Balancing Contingency Events.  A Balancing Contingency Event that is not a Reportable 
Balancing Contingency Event may impact the compliance requirement for the Reportable 
Balancing Contingency Event which occurs after it, because the megawatts lost for both may 
exceed the Most Severe Single Contingency.  Also, a subsequent Balancing Contingency Event 
may occur during the Contingency Event Recovery Period of a Reportable Balancing 
Contingency Event, affecting the ACE recovery requirement of the initial event.  The drafting 
team struggled with associating any specific time window for the megawatt loss to occur within 
for an event to qualify as a Balancing Contingency Event.  The term sudden implies an 
unexpected occurrence in the definition of a Balancing Contingency Event, and the Responsible 
Entity should use its best judgment in applying any time criterion to Balancing Contingency 
Events that do not qualify as Reportable Balancing Contingency Events.  
Most Severe Single Contingency  
The Most Severe Single Contingency (MSSC) term has been widely used within the industry; 
however, it has never been defined.  In order to eliminate a wide range of definitions, the 
drafting team has included a specific definition designed to fulfill the needs of the standard.  In 
addition, in order to meet FERC Order No. 693 (at P356), to develop a continent‐wide 
contingency reserve policy, it was necessary to establish a definition of MSSC. 
When an entity determines its MSSC, the review needs to include the largest loss of resource 
that might occur for either generation or transmission loss. If the loss of transmission causes 
the loss of generation and load, the size of that event would be the net change. Since the size of 
an event where both load and generation are lost due to the loss of the transmission would be 
less than just the loss of the generator, this event is unlikely to be the entity’s MSSC. Also, note 
here that the drafting team removed the previous requirement to review the MSSC at least 
annually. An entity should know what its MSSC is at all times. Therefore, an annual review is no 
longer required 
Contingency Reserve 
Most system operators generally have a good understanding of the need to balance resources 
and demand and return their Area Control Error to defined values following a Reportable 
Balancing Contingency Event.  However, the existing Contingency Reserve definition is focused 
primarily on generation and not sufficiently on Demand‐Side Management (DSM).  In order to 
meet FERC Order No. 693 (at P 356) to include a requirement that explicitly allows DSM to be 
used as a resource for contingency reserve, the drafting team elected to expand the definition 
of Contingency Reserve to explicitly include capacity associated with DSM.   
Additionally, conflict existed between BAL‐002 and EOP‐002 as to when an entity could deploy 
or restore its contingency reserve.  EOP‐002 also applies during the real‐time operations time 
horizon and addresses capacity and energy emergencies.  Given that an entity and/or event can 
transition suddenly from normal operations (BAL‐002) into emergency operations (EOP‐002), 
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Disturbance Control Performance ‐ Contingency Reserve for Recovery From a Balancing 
Contingency Event Standard Background Document 
this transitional seam must be explicitly addressed in order to provide clarity to responsible 
entities regarding the actions to be taken.   
To eliminate the possible conflict and to assure BAL‐002 and EOP‐002 work together and 
complement each other, the drafting team clarified the existing definition of Contingency 
Reserve.  The conflict arises since the actions required by Energy Deficient Entities before 
declaring either an Energy Emergency Alert 2 or an Energy Emergency Alert 3 include 
deployment of all Operating Reserve which includes Contingency Reserve.  Conversely, an 
Energy Deficient Entity may need to declare either an Energy Emergency Alert 2 or an Energy 
Emergency Alert 3, before incurring a Balancing Contingency Event.  The definition of 
Contingency Reserve now allows for deploying capacity to respond to a Balancing Contingency 
Event and other contingency requirements such as Energy Emergency Alerts.  Readiness to 
reduce Firm Demand during the Contingency Reserve Restoration Period during an Energy 
Emergency Alert  should another Contingency Event occur is proposed for inclusion in the 
definition of Contingency Reserve.  The Responsible Entity should have processes and 
procedures for direct control over the Firm Demand in place for it to be considered Contingency 
Reserves prior to the event during an Energy Emergency Alert.   
For additional technical justification for exemption from R1 to facilitate transitioning from 
normal operations into emergency operations please refer to Attachment 2. 
Reserve Sharing Group Reporting ACE 
The drafting team elected to include this definition to provide clarity for measurement of 
compliance of the appropriate Responsible Entity.  Additionally, this definition is necessary 
since the drafting team has eliminated R5.1 and R5.2 that are in the existing standard.  R5.1 and 
R5.2 mix definitions with performance.  The drafting team has included all the performance 
requirements in the proposed standards R1 and R2, and therefore has added the definition of 
Reserve Sharing Group Reporting ACE. 
Other Definitions 
Other definitions have been added or modified to assure clarification within the standard and 
requirements. 

Rationale by Requirement 
Requirement 1 
The Responsible Entity experiencing a Reportable Balancing Contingency Event shall: 

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Disturbance Control Performance ‐ Contingency Reserve for Recovery From a Balancing 
Contingency Event Standard Background Document 
1.1. within the Contingency Event Recovery Period, demonstrate recovery by 
returning its Reporting ACE to at least the recovery value of: 


zero (if its Pre‐Reporting Contingency Event ACE Value was positive or equal
to zero); however, any Balancing Contingency Event that occurs during the
Contingency Event Recovery Period shall reduce the required recovery: (i)
beginning at the time of, and (ii) by the magnitude of, such individual
Balancing Contingency Event,

or, 


its Pre‐Reporting Contingency Event ACE Value (if its Pre‐Reporting
Contingency Event ACE Value was negative); however, any Balancing
Contingency Event that occurs during the Contingency Event Recovery Period
shall reduce the required recovery: (i) beginning at the time of, and (ii) by the
magnitude of, such individual Balancing Contingency Event.

1.2. document all Reportable Balancing Contingency Events using CR Form 1. 
1.3. deploy Contingency Reserve, within system constraints, to respond to all 
Reportable Balancing Contingency Events, however, it is not subject to 
compliance with Requirement R1 part 1.1 if: 
1.3..1 the Responsible Entity: 


is a Balancing Authority experiencing  a Reliability Coordinator declared
Energy Emergency Alert Level or is a Reserve Sharing Group whose
member, or members, are experiencing a Reliability Coordinator
declared Energy Emergency Alert level, and



is utilizing its Contingency Reserve to mitigate an operating emergency
in accordance with its emergency Operating Plan, and



has depleted its Contingency Reserve to a level below its Most Severe
Single Contingency

or, 
1.3.2 the Responsible Entity experiences: 


multiple Contingencies where the combined MW loss exceeds its
Most Severe Single Contingency and that are defined as a single
Balancing Contingency Event, or



multiple Balancing Contingency Events within the sum of the time
periods defined by the Contingency Event Recovery Period and
Contingency Reserve Restoration Period whose combined magnitude
exceeds the Responsible Entity's Most Severe Single Contingency.

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Background and Rationale  
Requirement R1 reflects the operating principles first established by NERC Policy 1.  Its 
objective is to assure the Responsible Entity balances resources and demand and returns its 
Reportable Area Control Error (ACE) to defined values (subject to applicable limits) following a 
Reportable Balancing Contingency Event.  It requires the Responsible Entity to recover from 
events that would be less than or equal to the Responsible Entity’s MSSC.  It establishes 
recovery and restoration timeframes the Responsible Entity must demonstrate in a compliance 
evaluation.  It is intended to eliminate the ambiguities and questions associated with the 
existing standard.  In addition, it allows Responsible Entities to have a clear way to demonstrate 
compliance and support the Interconnection to the full extent of its MSSC. 
By including new definitions, and modifying existing definitions, and the above R1, the drafting 
team believes it has successfully fulfilled the requirements of FERC Order No. 693 (at P 356) to 
include a requirement that explicitly allows DSM to be used as a resource for Contingency 
Reserve. It also recognizes that the loss of transmission as well as generation may require the 
deployment of Contingency Reserve.   
Additionally, R1 is designed to assure the applicable entity uses reserve to cover a Reportable 
Balancing Contingency Event or the combination of any previous Balancing Contingency Events 
that have occurred within the specified period, to address the Order’s concern that the 
applicable entity is responding to events and performance is measured.  The Reportable 
Balancing Contingency Event definition, along with R1, allows for measurement of 
performance.   
In addition, the standard drafting team (SDT) through R1 Part 1.3 has clearly identified when R1 
is not applicable.  By including R1 Part 1.3.1, the proposed standard eliminates the existing 
conflict with the EOP Standards and further addresses the outstanding interpretation.  By 
clearly stating when R1 is not applicable or does not apply, it eliminates any auditor 
interpretation and allows the Responsible Entity to perform the function in a reliable manner.  
Requirement R1 does not apply when an entity experiences a Balancing Contingency Event that 
exceeds its MSSC (which includes multiple Balancing Contingency Events as described in R1 part 
1.3.2) because a fundamental goal of the SDT is to assure the Responsible Entity has enough 
flexibility to maintain service to load while managing reliability.  Also, the SDT’s intent is to 
eliminate any potential overlap or conflict with any other NERC Reliability Standard to eliminate 
duplicative reporting, and other issues. 
The drafting team used data supplied by the Consortium for Electric Reliability Technology 
Solutions (CERTS) to help determine all events that have an impact on frequency.  Data that 
was compiled by CERTS to provide information on measured frequency events is presented in 
Attachment 1.  Analyzing the data, reveals events of 100 MW or greater would capture all 
frequency events for all interconnections.  However, at a 100 MW reporting threshold, the 
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number of events reported would significantly increase with no reliability gain since 100 MW is 
more reflective of the outlying events, especially on larger interconnections. 
The goal of the drafting team was to design a continent‐wide standard to capture the majority 
of the events that impact frequency.  After reviewing the data and industry comments, the SDT 
elected to establish reporting threshold minimums for each respective Interconnection.  This 
assures the requirements of FERC Order No. 693 are met.  The reportable threshold was 
selected as the lesser of 80% of the applicable entity’s Most Severe Single Contingency or the 
following values for each respective Interconnection: 





Eastern Interconnection – 900 MW
Western Interconnection – 500 MW
ERCOT – 800 MW
Quebec – 500 MW

Additionally, the drafting team used only loss of resource events for purposes of determining 
the above thresholds. 
Violation Severity Levels 
In the Violation Severity Levels for Requirement R1, the impact of the Responsible Entity 
recovering from a Reportable Balancing Contingency Event depends on the percentage of 
desired recovery achieved.     
Compliance Calculation 
It is important to note that R1 adjusts the required recovery value of Reporting ACE for any 
other Balancing Contingency Events that occur during the Contingency Event Recovery Period.  
However, to determine compliance score for compliance with R1, the measured contingency 
reserve response (instead of the required recovery value of Reporting ACE) is adjusted for any 
other Balancing Contingency Events that occur during the Contingency Event Recovery Period. 
Both methods of adjustment are mathematically equivalent.  Accordingly, the measured 
contingency reserve response is computed and compared with the MW lost as follows 
(assuming all resource loss values, i.e. Balancing Contingency Events, are positive) to measure 
compliance1:  
•

The measured contingency reserve response is equal to one of the following:

1

 In adjusting for the adverse impact of rapidly succeeding (i.e. “near”) Events on a Responsible Entity’s Recovery 

from an Event, the SDT thought it more prudent to adjust for future near Events rather than for past near Events 
because the future Events place an added burden on performance, while adjusting for the past Events instead 
lowers the performance requirement.  To adjust for both future and past Events amounts to double dealing 
because an Event is subsequent to a prior near Event, and both Events would be serving to relieve Recovery from 
each other.  The SDT allowed only for the extreme case of exempting from recovery prior near Events that 
combined exceed MSSC. 

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o If the Pre‐Reportable Contingency Event ACE Value is greater than or equal
to zero, then the measured contingency reserve response equals (a) the
megawatt value of the Reportable Balancing Contingency Event plus (b) the
most positive ACE value within its Contingency Event Recovery Period (and
following the occurrence of the last subsequent event, if any)  plus (c) the
sum of the megawatt losses of the subsequent Balancing Contingency Events
occurring within the Contingency Event Recovery Period of the Reportable
Balancing Contingency Event.
o If the Pre‐Reportable Contingency Event ACE Value is less than zero, then the
measured contingency reserve response equals (a) the megawatt value of
the Reportable Balancing Contingency Event plus (b) the most positive ACE
value within its Contingency Event Recovery Period (and following the
occurrence of the last subsequent event, if any) plus (c) the sum of the
megawatt losses of subsequent Balancing Contingency Events occurring
within the Contingency Event Recovery Period of the Reportable Balancing
Contingency Event, minus (d) the Pre‐Reportable Contingency Event ACE
Value.
• Compliance is computed as follows on CR Form 1 in order to document all
Balancing Contingency Events used in compliance determination: 


If the measured contingency reserve response is greater than or
equal to the megawatts lost, then the Reportable Balancing
Contingency Event Compliance equals 100 percent.



If the measured contingency reserve response is less than or equal to
zero, then the Reportable Balancing Contingency Event Compliance
equals 0 percent.



If the measured contingency reserve response is less than the
megawatts lost but greater than zero, then the Reportable Balancing
Contingency Event Compliance equals 100% * (1 – ((megawatts lost –
measured contingency reserve response) / megawatts lost)).

The above computations can be expressed mathematically in the following 5 sequential steps, 
labeled as [1‐5], where: 
ACE_BEST – most positive ACE during the Contingency Event Recovery Period occurring after 
the last subsequent event, if any (MW) 
ACE_PRE ‐ Pre‐Reportable Contingency Event ACE Value (MW) 
COMPLIANCE ‐ Reportable Balancing Contingency Event Compliance percentage (0 ‐ 100%) 
MEAS_CR_RESP ‐ measured contingency reserve response for the Reportable Balancing 
Contingency Event (MW) 
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MSSC – Most Severe Single Contingency (MW) 
MW_LOST ‐ megawatt loss of the Reportable Balancing Contingency Event (MW) 
SUM_SUBSQ ‐ sum of the megawatt losses of subsequent Balancing Contingency Events 
occurring within the Contingency Event Recovery Period of the Reportable Balancing 
Contingency Event (MW) 
If ACE_PRE is greater than or equal to 0, then  
     MEAS_CR_RESP = MW_LOST +ACE_BEST + SUM_SUBSQ  [1] 
If ACE_PRE is less than 0, then  
     MEAS_CR_RESP = MW_LOST +ACE_BEST + SUM_SUBSQ – ACE_PRE [2] 
If MEAS_CR_RESP is greater than or equal to MW_LOST, then 
     COMPLIANCE = 100  [3] 
If MEAS_CR_RESP is less than or equal to 0, then 
     COMPLIANCE = 0  [4] 
If MEAS_CR_RESP is greater than 0, and, MEAS_CR_RESP is less than MW_LOST, then 
     COMPLIANCE = 100 * (1 – ((MW_LOST – MEAS_CR_RESP)/ MW_LOST))  [5] 

The Decision Tree flow diagram for DCS below, provides a visualization of the logic flow for a 
Reportable Balancing Contingency Event. It includes decision blocks for initial event 
determination, subsequent event determination, and checking for MSSC exceedance which
should assist the Responsible Entity with Event Recovery and analysis. 

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Document 

Decision Tree for DCS 
Adjust
Calculations

DCS Off
Line
Reporting

DCS Real
Time

Y

Start 15
Minute
Recovery

N
Subsequent
Events?

N
> MSSC

Y

Y
Resource Loss
> Reporting
Threshold

Complete
Form

Sudden?

Make Best
Efforts on
Recovery

N
If IROL or
BAAL
Exceeded, Begin
30 Min Recover

BAAL and
IROL

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Requirement 2 
R2.

Each Responsible Entity shall develop, review and maintain annually, and implement 
an Operating Process as part of its Operating Plan to determine its Most Severe 
Single Contingency and make preparations to have Contingency Reserve equal to, or 
greater than the Responsible Entity’s Most Severe Single Contingency available for 
maintaining system reliability. 

Background and Rationale  
R2 establishes a uniform continent‐wide contingency reserve policy in the form of a 
requirement that a Responsible Entity implement an Operating Plan that assures Contingency 
Reserve be at least equal to the applicable entity’s Most Severe Single Contingency and a 
definition of Most Severe Single Contingency.  Its goal is to assure that the Responsible Entity 
will have sufficient Contingency Reserve that can be deployed to meet R1. 
FERC Order 693 (at P356) directed BAL‐002 to be developed as a continent‐wide contingency 
reserve policy.  R2 fulfills the requirement associated with the required amount of contingency 
reserve a Responsible Entity must have available to respond to a Reportable Balancing 
Contingency Event.   Within FERC Order 693 (at P336) the Commission noted that the 
appropriate mix of operating reserve, spinning reserve and non‐spinning reserve should be 
addressed.  However, the Order predated the approval of the new BAL‐003, which addresses 
frequency responsive reserve and the amount of frequency response obligation.  With the 
development of BAL‐003, and the associated reliability performance requirement, the SDT 
believes that, with R2 of BAL‐002 and the approval of BAL‐003, the Commission’s goals of a 
continent‐wide contingency reserves policy is met.  The suites of BAL standards (BAL‐001, BAL‐
002, and BAL‐003) are all performance‐based.  With the suite of standards and the specific 
requirements within each respective standard, a continent‐wide contingency policy is 
established. 
The Responsible Entity’s Operating Plan will address the process by which Contingency 
Reserves greater than or equal to the Most Severe Single Contingency are available in Real‐
time. Once an entity utilizes its contingency reserve, Requirement R3 addresses restoration of 
the reserves.  

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Requirement 3 
R3.

Each Responsible Entity, following a Reportable Balancing Contingency Event, shall 
restore its Contingency Reserve to at least its Most Severe Single Contingency, 
before the end of the Contingency Reserve Restoration Period, but any Balancing 
Contingency Event that occurs before the end of a Contingency Reserve Restoration 
period resets the beginning of the Contingency Event Recovery Period. 

Background and Rationale  
Requirement R3 establishes the restoration of Contingency Reserves following Reportable 
Balancing Contingency Events. This requirement addresses the need to be prepared for future 
Balancing Contingency Events.  Contingency Reserves must be restored to at least the minimum 
required amount, the Most Severe Single Contingency, to assure that the next event for which 
an entity plans is expected to be covered if the event occurs.   Contingency Reserves must be 
restored within the Contingency Reserve Restoration Period which is defined as a period not 
exceeding 90 minutes following the end of the Contingency Event Recovery Period, which is 15 
minutes.     

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Attachment 1
NERC Interconnections 2009-2013
Frequency Events Loss MW Statistics

For: NERC BARC Standard Drafting Team
Prepared by: CERTS
Date: October 15, 2013

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Contingency Event Standard Background Document 

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Contingency Event Standard Background Document 

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Attachment 2
Technical Justification for Applicability
of BAL-002 During Emergency Alerts

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Technical Justification for Applicability of BAL‐002  
During Energy Emergency Alerts 
I.

 INTRODUCTION 

The Balancing Authority Reliability‐based Controls standard drafting team (BARC SDT) has 
identified a conflict between NERC Reliability Standards BAL‐002 and EOP‐002 that 
unnecessarily requires arbitrary interruption of Firm Load.  In order to address this issue, the 
BARC SDT is recommending that Standard BAL‐002‐2 not be enforceable during an Energy 
Emergency Alert (EEA) event where the EEA process requires the use of Contingency Reserve to 
maintain load service.2   This document provides support for this recommendation and an 
overview of reliable frequency management on the North American Interconnections. 
II.

BACKGROUND

Reliably balancing an Interconnection requires frequency management and all of its aspects.  
Inputs to frequency management include Tie‐Line Bias Control, Area Control Error (ACE), and 
the various Requirements in NERC Resource and Demand Balancing Standards, specifically BAL‐
001‐2 Real Power Balancing Control Performance and BAL‐003‐1 Frequency Response and 
Frequency Bias Setting.   
Reliability Standard BAL‐002 applies during the real‐time operations time horizon and 
addresses the balancing of resources and demand following a disturbance.  Reliability Standard 
EOP‐002 also applies during the real‐time operations time horizon and addresses capacity and 
energy emergencies. Given that an entity and/or event can transition suddenly from normal 
operations into emergency operations (EOP‐002) where Contingency Reserve maintained under 
BAL‐002 may be utilized to serve Firm Load, this transitional seam must be explicitly addressed 
in order to provide clarity to responsible entities regarding the actions to be taken.  The 
proposed applicability of BAL‐002 is designed to address this issue.  
III.

LEGACY REQUIREMENTS

The Resource and Demand Balancing (BAL) standards include both requirements that have a 
sound technical basis and legacy requirements that the industry has used for years but fail to 

2

   The proposed applicability section states:  “Applicability is determined on an individual Reportable Balancing 
Contingency Event basis, but the Responsible Entity is not subject to compliance during periods when the 
Responsible Entity is in an Energy Emergency Alert Level under which Contingency Reserves have been activated.” 

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have a sound technical basis.  NERC began replacing these legacy requirements with technically 
based requirements starting with the Control Performance Standard1 (CPS1).  Both Control 
Performance Standard2 (CPS2) and the Disturbance Control Standard (DCS) remain in the 
legacy category.  The following are specific concerns associated with these requirements. 
o When CPS1 was implemented to replace A1/A2, previous requirements were
modified so that CPS1 would apply at all times including the (disturbance)
periods where DCS is applicable, not just during normal operations/periods.  So
DCS is not the only standard governing disturbance conditions.
o The Disturbance Control Standard (DCS) and its precursor B1/B2 have been
unique in requiring immediate action by the Balancing Authority (BA), in this
case to address unexpected imbalances within defined limits.
o DCS, albeit results‐based in its current form, was initially designed to measure
the utilization of Contingency Reserve to address a loss of resource within the
defined limits.  In its results‐based form it assumed that implementing sufficient
Contingency Reserves as needed to comply with the recovery requirement
would be a reasonably equitable minimum quantity for all BAs participating in
interconnected operation.
o DCS is based upon ACE recovery to the lower of pre‐disturbance ACE or zero. A
Balancing Authority which might be under‐generating prior to a generation loss,
could lose a generating unit and under DCS be deemed compliant if it returned
ACE to its pre‐disturbance state, though it could still be depressing
Interconnection frequency.
o As DCS recovery from a reportable event must occur within a 15‐minute period,
it is possible for a Balancing Authority’s ACE to again go negative after that time,
with a similar impact on Interconnection frequency.
o Since CPS2 allows a BA to be unaccountable for approximately 74 hours of
operation in a 31‐day month, an imbalance condition may persist and negatively
impact Interconnection frequency for many hours3.
o When ACE is modulated by frequency, “significant” losses are defined not only
by the size of the event causing an ACE deviation, but also contingent on the
deviation of Interconnection frequency from Scheduled Frequency.
IV.

3

TIE‐LINE BIAS FREQUENCY CONTROL AND ACE

   Reliability‐Based Control v3, Standard Authorization Request Form, November 7, 2007. 

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Contingency Event Standard Background Document 
Tie‐Line Bias Frequency Control is implemented on the North American Interconnections 
through the use of the ACE Equation.4   In general, ACE is the term used to determine the load‐
generation imbalance that is being contributed by each Balancing Authority (BA) on an 
Interconnection.  ACE is a powerful indicator, because it indicates the imbalance within the 
boundaries of a single BA, thus defining the Secondary Control responsibilities for that BA and, 
therefore, the control action that would return ACE to zero.   ACE includes the Frequency Bias 
Setting term, which allows the Primary Frequency Control to be a shared service throughout a 
multi‐BA Interconnection, while assigning to each individual BA the specific responsibilities of 
maintaining its own Secondary Frequency Control. 
In summary, ACE only provides guidance with respect to Secondary Frequency Control and 
does not indicate or provide any direct measure of Primary Frequency Control, and only reflects 
the estimated Frequency Response as represented by the Frequency Bias Setting term.  NERC 
Requirements and supporting documentation for Frequency Response (Primary Frequency 
Control) are included in BAL‐003‐1 Frequency Response and Frequency Bias Setting standard.  
More detail on Tie‐Line Bias Frequency Control and ACE is attached.5  
V.

CONTROL PERFORMANCE STANDARD1 (CPS1)  

Prior to the development of CPS1, the industry assumed that, "It is impossible, however, to 
use frequency deviation to identify the specific control area (sic, i.e. BA) with the under‐ or 
over‐generation creating the frequency deviation…".3  In the 1990's the development of CPS1 
demonstrated that not only was it possible to identify the specific BA creating the frequency 
deviation, but that it is also possible not only to determine the relative contribution by each BA 
to the magnitude of the frequency deviation6, but also to determine the relative contribution of 
each BA to the reliability risk caused by that deviation.  In addition, the CPS1 Requirement 
provided a guarantee: "If all BAs on an interconnection complied with the CPS1 Requirement, 

4

   Illian, Howard F., Understanding ACE, CPS1 and BAAL, Prepared for the NERC BARC Standard Drafting Team, 
September 10, 2010 rev. August 19, 2014, Section 2, pp. 1‐4, for a derivation of the ACE Equation and the 
requirements for implementing it that are included in the definition of ACE appearing in the NERC Glossary.

5

  Illian, Howard F., Frequency Control Performance Measurement and Requirements, Ernest
Orlando Lawrence Berkeley National Laboratory, December 2010, for a discussion of the
history of Frequency Control and Performance Measurement.

6

   Illian, Howard F., Understanding ACE, CPS1 and BAAL, Section 2, pp. 5-10 for a derivation
of the CPS1 requirement.

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Contingency Event Standard Background Document 
the Root Mean Squared7 value of the frequency deviation for that Interconnection would be 
less than the epsilon18 frequency deviation limit for that Interconnection." 
CPS1 is a rolling annual average of individual measurements each averaged over one‐
minute, and is assessed monthly.  CPS1 measures the covariance between the ACE of a BA and 
the frequency deviation of the Interconnection which is equal to the sum of the ACEs of all of 
the BAs.  CPS1 has the great value of using the Interconnection frequency to determine the 
degree to which ACE among the BAs on a multiple BA Interconnection is harming or helping 
interconnection frequency.  Since the frequency deviation is a measured value, the ACE of a BA 
will directly affect only the CPS1 of the BA with the ACE and not the CPS1 measure of other BAs. 
VI.

BALANCING AUTHORITY ACE LIMIT (BAAL)

When the Balancing Resources and Demand (BRD) standard drafting team recognized the 
need for a control measure over a shorter time horizon than either CPS1 (annual) or Control 
Performance Standard 29 (CPS2, monthly) provided, it began looking for a measure that would 
allow a window for common imbalance events like a unit trip, while providing a limit on how 
much frequency deviation should be allowed over that short period.  After considering 
numerous alternatives, BAAL was selected as the appropriate short‐term measure.10,11 

7

   “Root Mean Squared” means the square root of the mean of the squared errors, so that
positive and negative errors do not offset each other and any shift in the mean is counted
as error.

8

   “Epsilon1” is the frequency deviation limit determined for each North American
Interconnection and used by CPS1 to bound the Root Mean Squared frequency deviation.
It is 18 mHz on the Eastern, 22.8 mHz on the Western, 30 mHz on the ERCOT, and 21
mHz on the Quebec Interconnections. 

9

Proposed to be replaced by BAAL under BAL-001-2, CPS2 requires the BA to move its ACE
within predefined L10 bounds when it is binding (during only 90% of the ten-minute
periods per month) without regard to whether such action helps or hurts Interconnection
frequency. 

10

   Illian, Howard F., Meeting the Discrete Event Measure (DEM) Objectives with the
Abnormal Operations Measure (AOM), Prepared for the NERC Balancing Resources and
Demand Standard Drafting Team, March 20, 2004. 

11

   Illian, Howard F., Setting the Balancing Authority ACE Limit (BAAL) for the NERC
Abnormal Operations Measure (AOM), Prepared for the NERC Balancing Resources and
Demand Standard Drafting Team, March 28, 2004.

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Contingency Event Standard Background Document 
Considerable evaluation and Field Trials have shown that BAAL12 is a better indicator of 
contributions to reliability risk of an interconnection than the magnitude of ACE alone.  This 
superiority, like CPS1’s, derives from the concurrent use of both ACE and frequency error in the 
BAAL measure. Thus BAAL captures the relative contribution to reliability by all of the ACEs on 
an interconnection and indicates where each BA stands relative to its secondary control 
responsibilities and the current state of the interconnection as indicated by the frequency error 
for both under‐ and over‐frequency conditions. 
VII.

INTERACTION BETWEEN STANDARDS

The drafting team has identified as an issue the existence of points where the standards are 
in conflict with each other. The drafting team has attempted to address the conflicts identified, 
as follows:  
NERC standard EOP‐002 requires a BA to use all its reserves during an Energy Emergency 
Alert 2 (EEA2) or higher. The following language is found in EOP‐002 Attachment 1‐EOP‐002: 
2.6.4 Operating Reserves. Operating reserves are being utilized such that the 
Energy Deficient Entity is carrying reserves below the required minimum or 
has initiated emergency assistance through its operating reserve sharing 
program. 
The current BAL‐002 specifies a minimum level reserve requirement at all times unless a 
qualifying event has occurred. The drafting team noted that in the EEA process an entity is 
driven to request an EEA rarely as the result of a single unit loss. In fact, an EEA declaration by 
the Reliability Coordinator might result from issues that include no event that would qualify as 
a Disturbance and the EEA situation could last longer than the reserve recovery period of 90 
minutes. For this reason, the drafting team recommends significant changes to the standards in 
question. 
In addition to the identified conflict, other standards can require the activation of 
contingency reserve. These include other BAL standards, IRO standards and TOP standards. 
Compared to those standards, the BAL‐002 standard provides the least direct measure of 
reliability. Therefore, an entity should never be conflicted between applying the requirements 
of BAL‐002 and complying with the other standards.  

12

  Illian, Howard F., Understanding ACE, CPS1 and BAAL, Prepared for the NERC BARC
Standard Drafting Team, September 10, 2010 rev. August 19, 2014, Section 2, pp. 10, for
a derivation of the BAAL requirement. 

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Contingency Event Standard Background Document 
Finally, there is one overarching principal not reflected in the discussion up to this point, 
namely keeping the lights on if possible. If there is a requirement to bring ACE back no matter 
what, then that requirement will have the unintended consequence of shedding Firm Load, 
especially during an EEA. During the EEA process, the expectation is that a BA will have firm 
load ready to shed in order to meet its reserve requirement under R2 of the proposed BAL‐002 
standard. However, if the BAL‐002 standard also requires the entity to meet R1 during the EEA, 
entities will shed firm load to restore ACE to its pre‐contingency level, regardless of the lack of 
any reliability issues. In other words, frequency could be settling at or very near 60 Hz, no 
transmission lines are overloaded as determined by the TOP standards, and the entity is 
operating within the parameters defined in BAL‐001, but firm load would be interrupted simply 
to bring the entity’s ACE back to what it was prior to the loss of the unit. Since the industry has 
defined reliability as frequency at or near 60 Hz and transmission lines operating within their 
limits, there is no reason to interrupt firm load. 
Instead, the BARC SDT is recommending that Standard BAL‐002‐2 not be enforceable 
during an EEA event where the EEA process requires the use of Contingency Reserve to 
maintain load service. Instead, the Reliability Coordinator, Transmission Operators and the 
impacted Balancing Authorities should use real‐time situational awareness, taking into account 
issues addressed in BAL‐001, BAL‐003, the IRO suite of standards and the TOP suite of 
standards, to determine what actions are appropriate when conditions are abnormal. This 
process would allow continued load service without arbitrarily requiring interruption of firm 
load.  
This concern arises because the other standards look at specific reliability issues other 
than just balancing between scheduled and actual interchange. BAL‐001‐2 and BAL‐003‐1 look 
at interconnection frequency to determine whether the Balancing Authority is helping or 
hurting reliability. During an EEA event, curtailing load to move ACE back to a pre‐event level 
could adversely affect frequency. If frequency goes up from 60 Hz when a Balancing Authority 
interrupts load, the impact is detrimental to the interconnection. Under the TOP standards, if 
flows on transmission lines are within the limits specified, there is no need to alter the flows on 
the transmission system by interrupting load.  
Finally, the Reliability Coordinator has a wide area view of the electric system as 
required under the IRO standards. The IRO standards clearly state the Reliability Coordinator’s 
responsibilities during the EEA process. If the Reliability Coordinator has not identified a 
reliability concern in its near term operations evaluation, actions such as interruption of firm 
load should not occur simply to balance load and resources within the BA. During abnormal 
(emergency) situations, taking significant actions with a narrow view will not be beneficial for 
Interconnection reliability.  
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Contingency Event Standard Background Document 
EXAMPLES 
o Example 1
On an usually cold day in February 2011, at 06:22, a Balancing Authority Area
(BAA) experienced a 350 MW generation loss when a 750 MW joint ownership
unit tripped off‐line.  Earlier in the day the BAA operator experienced loss of
several generating units with a total capacity of 1050 MW, the latest loss being
just 38 minutes prior to the 350 MW loss.  When the 350 MW event occurred
the BAA operator requested reserve/emergency assistance, shed 300 MW of
customer load to restore contingency reserve, and requested the RC post an
EEA3.  The EEA3 was posted.   Although the frequency only touched 59.91 Hz,
averaging 59.951 Hz in the first minute of the outage, was it really necessary to
cut load and leave people in the cold, dark of that morning to restore
contingency reserve?  Having idle generation, when the Interconnection is
operating reliably, does not warrant shedding customer load.
o Example 2
In June 2012, at 17:08, a BAA experienced an 800 MW generation loss.  The BA
and the reserve sharing group (RSG) it participates in were in the process of
replacing the lost generation when, in the thirteenth minute of the recovery
when there were no identified frequency, voltage or loading threats to reliability,
the BAA was directed by its Reliability Coordinator (RC) to shed 120 MW of
customer load.  Although the combined Area Control Error (ACE) of the RSG
participants was positive, the RC focused on the ACE of the BAA that lost the
generation – which was still negative – ignoring the fact that the Interconnection
frequency (59.96 Hz) was above the Frequency Trigger Limit (59.932 Hz).   The
needless shedding of customer load when system reliability is not threatened
attracted the attention of state regulators who were not happy with the action.
This demonstrates that focusing solely on a BAA’s ACE and not on the true
Interconnection reliability indicators can cause actions that do not support
reliability.
o Example 3
In June 2004, at 0741, a series of events led to a generation loss of over 4,600
MW.  In spite of the event size, the Interconnection frequency was arrested
without triggering automatic underfrequency load shedding, thanks to governor
action, frequency sensitive load and deployment of Contingency Reserve (as
required by BAL‐002).  Some transmission elements exceeded their limits for a
short time (as permitted by the EOP standards),   And, prior to the disturbance,
the frequency was in the normal operating range due to automatic generation
control (AGC) operation (as required by BAL‐001).  During the event almost 1,000
MW of interruptible customer load was shed throughout the interconnected
systems by devices that automatically operated to protect various parts of the
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Contingency Event Standard Background Document 
system (as determined by the TPL and TOP Standards).   This demonstrates how 
the suite of standards defined by NERC work together to efficiently protect the 
system and minimize customer interruptions. 
VIII.

CONCLUSIONS

There are important conclusions that can be drawn from this work and the 
mathematical guarantees that it provides: 
o The Disturbance Control Standard (DCS) as currently configured only looks at
ACE, the imbalance contribution of a single BA, and does not include a specific
frequency error component that indicates the BA’s contribution relative to the
condition of the interconnection to which the BA is connected.
o As the DCS measure does not have a specific frequency component, compliance
to DCS at times conflicts with the overall goal of targeting operation within
predefined Interconnection frequency limits. For example, DCS recovery initiated
from above Scheduled Frequency has a detrimental impact on Interconnection
frequency.
o The focus on ACE alone is insufficient to control frequency on a multiple BA
Interconnection.  The correlation of the ACEs among the BAs on the
Interconnection will affect the quality of frequency control independent of how
any individual ACE is controlled.
o Adequate control of Interconnection frequency requires the use of both ACE
(individual BA balancing error) and frequency deviation.
o Adequate control of reliability risk on an Interconnection requires the use of
ACE, frequency deviation and available frequency response.
o BAAL addresses all events impacting Interconnection frequency, both above and
below scheduled frequency.
BAAL addresses all of the above issues in its time domain without requiring response to or 
measurement of events that fail to raise reliability concerns.  For these reasons, the proposed 
applicability of BAL‐002 is a reasonable and technically‐justified approach that addresses the 
seam with EOP‐002. 

BAL‐002‐2 ‐ Background Document 

29 

Exhibit F
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 revisions reflected in proposed Reliability Standard has met or
exceeded the criteria.
1. Proposed Reliability Standards must be designed to achieve a specified reliability
goal and must contain a technically sound means to achieve that goal. 2
Proposed Reliability Standard BAL-002-2, attached as Exhibit C, achieves the specific
reliability goal of ensuring that the Balancing Authority or Reserve Sharing Group balances
resources and demand and returns the Balancing Authority’s or Reserve Sharing Group’s Area
Control Error to defined values (subject to applicable limits) following a Reportable Balancing
Contingency Event. Proposed Reliability Standard BAL-002-2 balances an Interconnection
requiring frequency management by ensuring recovery of the Reportable Area Control Area
(ACE), a value determined to be helpful in ensuring system stability, and appropriate levels of
Contingency Reserves following a Reportable Balancing Contingency Event. This standard,
along with BAL-001-2 Real Power Balancing Control Performance and BAL-003-1 Frequency
Response and Frequency Bias Setting, utilize frequency management inputs, including Tie-Line
Bias Control, ACE, and other various inputs from requirements in NERC Resource and Demand
Balancing Standards.

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 PP 321, 324.

1

2. Proposed Reliability Standards must be applicable only to users, owners and
operators of the bulk power system, and must be clear and unambiguous as to what
is required and who is required to comply. 3
The proposed Reliability Standard is applicable only to users, owners, and operators of
the bulk power system and is clear and unambiguous as to what is required and who is
required to comply, in accordance with Order No. 672. The proposed Reliability Standard
applies to Reserve Sharing Groups and a Balancing Authorities, but a Balancing Authority that
is a member of a Reserve Sharing Group is the Responsible Entity only in periods during which
the Balancing Authority is not in active status under the applicable agreement or governing
rules for the Reserve Sharing Group. The proposed Reliability Standard clearly articulates the
actions that such entities must take to comply with the standard, each of which are triggered
by articulable actions and situations.
3. A proposed Reliability Standard must include clear and understandable
consequences and a range of penalties (monetary and/or non-monetary) for a
violation. 4
The Violation Risk Factors (“VRFs”) and Violation Severity Levels (“VSLs”) for the
proposed Reliability Standard, attached as Exhibit G, 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 will 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 Standard includes clear and understandable consequences
in accordance with Order No. 672.

3
4

Order No. 672 at PP 322, 325.
Order No. 672 at P 326.

2

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 nonpreferential manner. 5
The proposed Reliability Standard contains Measures that support each Requirement by
clearly identifying what is required to demonstrate compliance and how the Requirement will be
enforced. The Measures are as follows:
M1. Each Responsible Entity shall have, and provide upon request, as evidence, a
CR Form 1 with date and time of occurrence to show compliance with Requirement
R1. If Requirement R1 part 1.3 applies, then dated documentation that demonstrates
compliance with Requirement R1 part 1.3 must also be provided.
M2. Each Responsible Entity will have the following documentation to show
compliance with Requirement R2:
• a dated Operating Process;
• evidence to indicate that the Operating Process has been reviewed and
maintained annually; and,
• evidence such as Operating Plans or other operator documentation that
demonstrate that the entity determines its Most Severe Single
Contingency and that Contingency Reserves equal to or greater than its
Most Severe Single Contingency are included in this process.
M3. Each Responsible Entity will have documentation demonstrating its
Contingency Reserve was restored within the Contingency Reserve Restoration
Period, such as historical data, computer logs or operator logs.
The above 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 Standard achieves the reliability goal effectively and efficiently
in accordance with Order No. 672. The proposed Reliability Standard clearly enumerates the
responsibilities of applicable entities with respect to balancing resources and demands, including

5
6

Order No. 672 at P 327.
Order No. 672 at P 328.

3

deployment and subsequent recovery of adequate levels of Contingency Reserves, to return the
Area Control Error to defined values. The proposed Reliability Standard provides entities with
the flexibility to tailor their processes and plans to take into account system dynamics and
characteristics while still maintaining reliability of the Bulk Power System.
6. Proposed Reliability Standards cannot be “lowest common denominator,” i.e.,
cannot reflect a compromise that does not adequately protect Bulk-Power System
reliability. Proposed Reliability Standards can consider costs to implement for
smaller entities, but not at consequences of less than excellence in operating system
reliability.7
The proposed Reliability Standard does not reflect a “lowest common denominator”
approach. To the contrary, the proposed standard represents significant benefits for the
reliability of the Bulk Power System because it requires entities to protect system stability by
recovering an entity’s Reporting Area Control Error and requisite levels of Contingency
Reserves. The proposed Reliability Standard does not sacrifice excellence in operating system
reliability for costs associated with implementation of the Reliability Standard.
7. Reliability Standards must be designed to apply throughout North America to the
maximum extent achievable with a single Reliability Standard while not favoring one
geographic area or regional model. It should take into account regional variations in
the organization and corporate structures of transmission owners and operators,
variations in generation fuel type and ownership patterns, and regional variations in
market design if these affect the proposed Reliability Standard.8
The proposed Reliability Standard applies throughout North America and does not favor
one geographic area or regional model.
8. Proposed Reliability Standards should cause no undue negative effect on
competition or restriction of the grid beyond any restriction necessary for
reliability. 9
The proposed Reliability Standard has no undue negative impact on competition. The
proposed Reliability Standard requires the same performance by each applicable entity. The standard

7
8
9

Order No. 672 at P 329-30.
Order No. 672 at P 331.
Order No. 672 at P 332.

4

does 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 date for the standard is just and reasonable and appropriately
balances the urgency in the need to implement the standard against the reasonableness of the
time allowed for those who must comply to develop necessary procedures, software, facilities,
staffing or other relevant capability. The proposed Implementation Plan, attached as Exhibit D,
will allow applicable entities adequate time to ensure compliance with the requirements. The
proposed effective date is explained in the attached Implementation Plan for BAL-002-2.
10. The Reliability Standard was developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development
process. 11
The proposed Reliability Standard was developed in accordance with NERC’s
Commission approved, ANSI-accredited processes for developing and approving Reliability
Standards. 12 Exhibit H includes a summary of the Reliability Standard development
proceedings and details the processes followed to develop the Reliability Standard. These
processes included, among other things, multiple comment periods, pre-ballot review periods,
and balloting periods. Additionally, all meetings of the standard drafting team were properly
noticed and open to the public.
11. NERC must explain any balancing of vital public interests in the development of
proposed Reliability Standards. 13
NERC has identified no competing public interests regarding the request for approval of
proposed Reliability Standard BAL-002-2. No comments were received that indicated the

10

Order No. 672 at P 333.
Order No. 672 at P 334.
12
See NERC Rules of Procedure, Section 300 (Reliability Standards Development) and Appendix 3A (Standard
Processes Manual).
13
Order No. 672 at P 335.
11

5

proposed Reliability Standard conflict with other vital public interests.
12. Proposed Reliability Standards must consider any other appropriate factors. 14
NERC has identified no other factors relevant to whether the proposed Reliability
Standard BAL-002-2 is just and reasonable

14

Order No. 672 at P 323.

6

Exhibit G
Analysis of Violation Risk Factors and Violation Severity Levels

Violation Risk Factor and Violation Severity
Level Assignments

Project 2010-14.1 Balancing Authority Reliability-based Controls
- Reserves
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‐002‐2, Contingency Reserve for 
Recovery from a Balancing Contingency Event.  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 
BAL‐002‐2  
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.

BAL‐002‐2  
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 BAL-002-2:

There are two requirements in BAL‐002‐2.  Both requirements were assigned a “Medium” VRF.   
VRF for BAL-002-2, Requirement R1:

•

FERC Guideline 2 — Consistency within a reliability standard exists.  The requirement does not
contain sub‐requirements.  All of the requirements in BAL‐002‐2 are assigned a “Medium” VRF.
Requirement R1 is similar in scope to Requirement R2.  This is also consistent with other
reliability standards (i.e., BAL‐001‐2, BAL‐003‐1, etc).

•

FERC Guideline 3 — Consistency among reliability standards exists.  This requirement is similar
in concept to the current enforceable BAL‐001‐0.1a Standard Requirements R1 and R2, which
have an approved Medium VRF and approved reliability standards BAL‐001‐1 and BAL‐003‐1.

•

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

BAL‐002‐2  
VRF and VSL Assignments  

3 

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-002-2, Requirement R2:

•

FERC Guideline 2 — Consistency within a reliability standard exists.  The requirement does not
contain subrequirements.  All of the requirements in BAL‐002‐2 are assigned a “Medium” VRF.
Requirement R2 is similar in scope to Requirement R1.  This is also consistent with other
reliability standards (i.e., BAL‐001‐2, BAL‐003‐1, etc).

•

FERC Guideline 3 — Consistency among Reliability Standards exists.  This requirement is similar
in concept to the current enforceable BAL‐001‐0.1a standard Requirements R1 and R2, which
have an approved Medium VRF and approved reliability standards BAL‐001‐1 and BAL‐003‐1.

•

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-002-2, Requirement R3:

•

FERC Guideline 2 — Consistency within a reliability standard exists.  The requirement does not
contain subrequirements.  All of the requirements in BAL‐002‐2 are assigned a “Medium” VRF.  .
This is also consistent with other reliability standards (i.e., BAL‐001‐2, BAL‐003‐1, etc).

•

FERC Guideline 3 — Consistency among Reliability Standards exists.  This requirement is similar
in concept to the current enforceable BAL‐001‐0.1a standard Requirements R1 and R2, which
have an approved Medium VRF, and approved reliability standards BAL‐001‐1 and BAL‐003‐1.

•

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

BAL‐002‐2  
VRF and VSL Assignments  

4 

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‐002‐2  
VRF and VSL Assignments  

5 

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‐002‐2 meet the FERC Guidelines for assessing VSLs: 

BAL‐002‐2  
VRF and VSL Assignments  

6 

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‐002‐2  
VRF and VSL Assignments  

7 

VSLs for BAL-002-2 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.  The VSLs 
assigned only consider 
results of the calculation 
required.  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

R1 

The NERC VSL 
Guidelines are 
satisfied by 
incorporating 
percentage of 
noncompliance 
performance for 
the calculated 
CPS1. 

BAL‐002‐2  
VRF and VSL Assignments  

As drafted, the 
proposed VSLs do not 
lower the current level 
of compliance. 

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 percentage of 
intervals the entity is 
noncompliant. 

8

VSLs for BAL-002-2 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 
Guidelines are 
satisfied by 
incorporating 
levels of 
noncompliance 
performance. 

BAL‐002‐2  
VRF and VSL Assignments  

This is a new requirement.   
As drafted, the proposed 
VSLs do not lower the 
current level of compliance. 

Proposed VSLs are not 
binary.  Proposed VSL 
language does not include 
ambiguous terms and 
ensures uniformity and 
consistency in the 
determination of penalties. 

9

VSLs for BAL-002-2 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. 

BAL‐002‐2  
VRF and VSL Assignments  

This is similar to the current 
BAL‐002‐1 Requirement 
R3.1.   As drafted, the 
proposed VSLs do not lower 
the current level of 
compliance. 

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 
contingency reserve 
recovered. 

10 

Exhibit H
Summary of Development History and Complete Record of Development

Summary of Development History
The development record for proposed Reliability Standard BAL-002-2 is summarized
below.
I.

Overview of the Standard Drafting Team
When evaluating a proposed Reliability Standard, the Commission is expected to

give “due weight” to the technical expertise of the ERO. 1 The technical expertise of the
ERO is derived from the standard drafting team selected to lead each project in
accordance with Section 4.3 of the NERC Standard Processes 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 K.
II.

Standard Development History

A. Standard Authorization Request Development
The Standards Committee (“SC”) approved the merger of Project 2007-05
(Balancing Authority Controls) and Project 2007-18 (Reliability-based Controls) to
create Project 2010-14 (Balancing Authority Reliability-based Controls) on July 28,
2010. The SC subsequently approved the division of Project 2010-14 (Balancing
Authority Reliability-based Controls) into two phases and the transition of Phase 1
(Project 2010- 14.1, Balancing Authority Reliability-based Controls – Reserves) into
formal standards development on July 13, 2011. A Standard Authorization Request
(“SAR”) for Project 2010-14.1 Phase 1 of Balancing Authority Reliability-based

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

Controls: Reserves was posted for a 30-day formal comment period from June 4, 2012
through July 3, 2012.
B. Initial and First Comment Period, Initial Ballot, and Non-Binding Poll
Proposed Reliability Standard BAL-002-2 was posted for the initial formal 30-day
public comment period from June 4, 2012 through July 3, 2012 and the first formal 45day public comment period from March 12, 2013 through April 25, 2013. Several
associated documents were posted for consideration and approval together with the draft
standard, including the Unofficial Comment Form, Mapping Document, and Violation
Risk Factors (“VRFs”) and Violation Severity Levels (“VSLs”) Justification Documents.
The Non-Binding Poll reached quorum at 86.46% of the ballot pool, and the standard and
associated documents received support from only 43.96% of the voters.
The standard was posted for the initial 10-day ballot simultaneously with the first
formal 45-day public comment period from April 16, 2013 through April 25, 2013. The
initial ballot reached quorum at 88.51% of the ballot pool, and the standard and
associated documents received support from only 42.75% of the voters. There were 55
sets of comments, including comments from approximately 179 different individuals and
approximately 108 companies, representing all 10 industry segments. 3
C. Second Comment Period, Additional Ballot and Non-Binding Poll
Proposed Reliability Standard BAL-002-2 was posted for an additional 45-day
formal comment period from August 2, 2013 through September 17, 2013, with an
additional parallel ballot held from September 6, 2013 through September 17, 2013. The

3

NERC, Consideration of Comments, Project 2010-14.1, available at
http://www.nerc.com/pa/Stand/Project%202010141%20%20Phase%201%20of%20Balancing%20Authority%20Re/
Comment_Report_2010-14.1_BARC_BAL-002-2-20130731.pdf.

2

additional ballot reached quorum at 76.15% of the ballot pool, and the standard and
associated documents received support from 58.23% of the voters. The related NonBinding Poll reached quorum at 75.69% of the ballot pool, and the standard and
associated documents received support from 59.66% of the voters. There were 35 sets of
comments, including comments from approximately 100 different individuals and
approximately 66 companies, representing 7 of the 10 industry segments. 4
D. Third Comment Period, Additional Ballot and Non-Binding Poll
Proposed Reliability Standard BAL-002-2 was posted for an additional 45-day
formal comment period from October 28, 2013 through December 11, 2013, with an
additional parallel ballot held from December 2, 2013 through December 12, 2013. The
additional ballot reached quorum at 75.29% of the ballot pool, and the standard and
associated documents received support from 64.24% of the voters. The related NonBinding Poll reached quorum at 76.62% of the ballot pool, and the standard and
associated documents received support from 66.67% of the voters. There were 32 sets of
comments, including comments from approximately 90 different individuals and
approximately 70 companies, representing all 10 industry segments. 5
E. Fourth Comment Period, Additional Ballot and Non-Binding Poll
Proposed Reliability Standard BAL-002-2 was posted for an additional 45-day
formal comment period from August 19, 2014 through October 3, 2014, with an
additional parallel ballot held from September 23, 2014 through October 3, 2014. The
4

NERC, Consideration of Comments, Project 2010-14.1, (October 15, 2013), available at
http://www.nerc.com/pa/Stand/Project%202010141%20%20Phase%201%20of%20Balancing%20Authority%20Re/
Project2010-141BARCBAL-002-2SummaryofComments-20131021.pdf.
5
NERC, Consideration of Comments, Project 2010-14.1, (August 2014), available at
http://www.nerc.com/pa/Stand/Project%202010141%20%20Phase%201%20of%20Balancing%20Authority%20Re/
Project%202010-14%201%20BARC%20BAL-002-2%20Summary%20of%20Comments%20%202014%2006%2001.pdf.

3

additional ballot reached quorum at 79.94% of the ballot pool, and the standard and
associated documents received support from 46.73% of the voters. The related NonBinding Poll reached quorum at 76.49% of the ballot pool, and the standard and
associated documents received supportive opinions from only 54.12% of the voters.
There were 28 sets of comments, including comments from approximately 109 different
individuals and approximately 74 companies, representing all 10 industry segments. 6
F. Fifth Comment Period, Additional Ballot and Non-Binding Poll
Proposed Reliability Standard BAL-002-2 was posted for an additional 45-day
formal comment period from January 29, 2015 through March 18, 2015, with an
additional parallel ballot held from March 6, 2015 through March 18, 2015. The
additional ballot reached quorum at 77.29% of the ballot pool, and the standard and
associated documents received support from 59.83% of the voters. The Non-Binding
Poll reached quorum at 75.86% of the ballot pool, and the standard and associated
documents received supportive opinions from 70.93% of the voters. There were 24 sets
of comments, including comments from approximately 116 different individuals and
approximately 80 companies, representing 9 of the 10 industry segments. 7
G. Sixth Comment Period, Additional Ballot and Non-Binding Poll
Proposed Reliability Standard BAL-002-2 was posted for an additional 45-day
formal comment period from July 7, 2015 through August 20, 2015, with an additional
parallel ballot held from August 11, 2015 through August 21, 2015. The additional ballot
6

NERC, Consideration of Comments, Project 2010-14.1, (January 2015), available at
http://www.nerc.com/pa/Stand/Project%202010141%20%20Phase%201%20of%20Balancing%20Authority%20Re/
Project%202010-14%201%20BARC%20BAL-002-2%20Summary%20of%20Comments%20%202015%2001%2026.pdf.
7
NERC, Consideration of Comments, Project 2010-14.1, available at
http://www.nerc.com/pa/Stand/Project%202010141%20%20Phase%201%20of%20Balancing%20Authority%20Re/
2010-14_1_Consideration_of_Comments_BARC_BAL-002-2_20150701.pdf.

4

reached quorum at 75.92% of the ballot pool, and the standard and associated documents
received support from 69.26% of the voters. The Non-Binding Poll reached quorum at
79.42% of the ballot pool, and the standard and associated documents received supportive
opinions from 69.28% of the voters. There were 33 sets of comments, including
comments from approximately 87 different individuals and approximately 63 companies,
representing 8 of the 10 industry segments. 8
H. Final Ballot
Proposed Reliability Standard BAL-002-2 was posted for a 10-day final ballot
period from September 29, 2015 through October 8, 2015. The ballot for the proposed
Reliability Standard and associated documents reached quorum at 84.28% of the ballot
pool, and the standard received sufficient affirmative votes for approval, receiving
support from 74.61% of the voters. 9
I. Board of Trustees Adoption
Proposed Reliability Standard BAL-002-2 was adopted by the NERC Board of Trustees
on November 5, 2015. 10

8

NERC, Consideration of Comments, Project 2010-14.1, available at
http://www.nerc.com/pa/Stand/Project%202010141%20%20Phase%201%20of%20Balancing%20Authority%20Re/
2010-14_1_BAL-002-2_Consideration_of_Comments_09292015.pdf.
9

NERC, Standards Announcement, Project 2010-14.1, available at
http://www.nerc.com/pa/Stand/Project%202010141%20%20Phase%201%20of%20Balancing%20Authority%20Re/
2010-14.1_BARC_BAL-002-2_FB_Results_Word_Announce_10092015.pdf.

10
NERC, Board of Trustees Agenda Package, Agenda Item 4.c. (Project 2010-14.1 Phase 1 of Balancing
Authority Reliability-based Controls (BAL-002), available at
http://www.nerc.com/gov/bot/botquarterlyitems/Board_Agenda_Package_November_2015_v3a.pdf.

5

Complete Record of Development

Background Document
Clean (146) | Redline to Last Posted
(147)

Supporting Materials

Implementation Plan
Clean (144) | Redline to Last Posted
(145)

BAL-002-2
Clean (142) | Redline to Last Posted
(143)

Draft 7

Draft

Info

Revised Draft RSAW

Vote

Info (150)

Final Ballot

Action

09/29/15 - 10/08/15

Dates

Ballot Results (152)

Summary (151)

Results

Consideration of
Comments

The standards within Project 2010-14.1 are an important part of the ERO's strategic goal to develop technically sufficient standards with requirements that provide clear and unambiguous performance expectations and
reliability benefits.

Background
The NERC Standards Committee approved the merger of Project 2007-05 Balancing Authority Controls and Project 2007-18 Reliability-based Control as Project 2010-14 Balancing Authority Reliability-based Controls on July
28, 2010. The NERC Standards Committee also approved the separation of Project 2010-14 Balancing Authority Reliability-based Controls into two phases and moving Phase 1 (Project 2010-14.1 Balancing Authority
Reliability-based Controls - Reserves) into formal standards development on July 13, 2011. The Project 2010-14.1 Phase 1 proposes revisions to BAL-001-0.1a Real Power Balancing Control Performance and BAL-002-1
Disturbance Control Performance. The project also initially proposed two new standards, BAL-012-1 Operating Reserve Policy and BAL-013-1 Large Loss of Load Performance. BAL-012-1 was posted for a 45-day formal
comment period with an initial ballot and non-binding poll through January 14, 2013. The initial ballot failed to achieve the required two-thirds industry approval. Based on industry comments received during this ballot
period, the drafting team elected to cease any further development of the proposed BAL-012-1 standard. This project will address the FERC Order 693 Directive for development of a continent-wide Contingency Reserve
standard.

- FERC Final Rule “Mandatory Reliability Standards for the Bulk-Power System, FERC Order 693” on the NERC standards BAL-002.
- Issues raised by stakeholders and compliance teams related to BAL-001-0.1a Real Power Balancing Control Performance and BAL-002-1 Disturbance Control Performance.
- To ensure that when finalized, the standards associated with this project conform to the latest versions of NERC’s Reliability Standards Development Procedure.

This project is intended to address the following:

Purpose/Industry Need
The purpose of this project is to ensure that Balancing Authorities take actions to maintain interconnection frequency with each Balancing Authority contributing its fair share to frequency control.

Status
A final ballot for BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event concluded 8 p.m. Eastern, Thursday, October 8, 2015. The voting
results can be accessed via the links below. The standard will be submitted to the Board of Trustees for adoption and then filed with the appropriate regulatory authorities.

Related Files | Field Trial Documents and Tools | Project 2007-05 - Balancing Authority Controls | Project 2007-18 - Reliability-based Control

Project 2010-14.1 Phase 1 of Balancing Authority Reliability-based Controls: Reserves

Program Areas & Departments > Standards > Project 2010-14.1 Phase 1 of Balancing Authority Reliability-based Controls: Reserves

Vote

Comment Period

Unofficial Comment Form (Word) (129)

Background Document
Clean (130) | Redline to Last Posting
(131)

CR Form 1

[email protected]

Please send RSAW feedback to:

If you previously joined the ballot pools for BAL002-2,
you must join these ballot pools to cast a vote.
Previous BAL-002-2 ballot pool members will
notbe carried
over to these ballot pools.

Join Ballot Pools

Submit Comments

Info (134)

Info (137)

Supporting Materials

Mapping Document
Clean (132) | Redline to Last Posting
(133)

Updated Info (136)

The ballot and non-binding poll for this posting
are additional.
Since the previous ballot pools for this project are
outdated,
new ballot pools are being formed in the SBS.

BAL-002-2
Clean (125) | Redline to Last Posting
(126)

Implementation Plan
Clean (127) | Redline to Last Posting
(128)

Additional Ballot and Non-binding Poll

Draft 7

VRF/VSL Justification
Clean (148) | Redline to Last Posted
(149)

Revised Draft Reliability Standard Audit
Worksheet (RSAW)

07/22/15 - 08/20/15

07/07/15 - 08/05/15

07/07/15 - 08/20/15

Non-binding Poll extended an additional day
(from 8/20/15) to reach quorum

08/11/15 - 08/21/15

Posted for Information October 6, 2015

Comments Received
(135)

Non-binding Poll
Results (140)

Ballot Results (139)

Summary (138)

Consideration of
Comments (141)

Draft RSAW

CR Form 1

Mapping Document (100)

Background Document
Clean (98) |Redline to Last Posting (99)

Unofficial Comment Form (Word) (97)

Supporting Materials

Implementation Plan
Clean (95) |Redline to Last Posting (96)

BAL-002-2
Clean (93) |Redline to Last Posting (94)

Draft 5

Draft RSAW

CR Form 1

Mapping Document (116)

Background Document
Clean (114) | Redline to Last Posting
(115)

Unofficial Comment Form (Word) (113)

Supporting Materials

Implementation Plan
Clean (111) | Redline to Last Posting
(112)

BAL-002-2
Clean (109) | Redline to Last Posting
(110)

Draft 6

Draft RSAW

[email protected]

Please send RSAW feedback to:

Submit Comments

Info (101)

Comment Period

Vote

Info (104)

Updated Info (103)

Additional Ballot and Non-binding Poll

[email protected]

Please send RSAW feedback to:

Submit Comments

Info (117)

Comment Period

Vote

Info (120)

Updated Info (119)

Additional Ballot and Non-binding Poll

09/11/14 - 10/03/14

08/19/14 – 10/03/14

09/23/14 – 10/03/14

02/16/15 - 03/18/15

01/29/15 – 03/18/15

Extended an additional day to reach quorum

03/06/15 – 03/18/15

Comments Received
(102)

Non-binding Poll
Results (107)

Ballot Results (106)

Summary (105)

Comments Received
(118)

Non-binding Poll
Results (123)

Ballot Results (122)

Summary (121)

Consideration of
Comments (108)

Consideration of
Comments (124)

Implementation Plan

BAL-001-2
Clean (46) | Redline to Last Posting (47)

CR Form 1

Mapping Document
Clean (67) | Redline to Last Posting (68)

VRF/VSL Justification (66)

Background Document
Clean (64) | Redline to Last Posting (65)

Unofficial Comment Form (Word) (63)

Supporting Materials

Info (56)

Final Ballot

Submit Comments

Info (69)

Comment Period

Vote

Updated Info (71)

BAL-002-2
Clean (59) | Redline to Last Posting (60)

Implementation Plan
Clean (61) | Redline to Last Posting (62)

Additional Ballot

Submit Comments

Info (85)

Comment Period

Vote

Info (88)

Updated Info (87)

Additional Ballot and Non-binding Poll

Draft 3

CR Form 1

Mapping Document
Clean (83) |Redline to Last Posting (84)

Background Document
Clean (81) |Redline to Last Posting (82)

Unofficial Comment Form (Word) (80)

Supporting Materials

Implementation Plan
Clean (78) |Redline to Last Posting (79)

BAL-002-2
Clean (76) |Redline to Last Posting (77)

Draft 4

07/16/13 - 07/25/13

08/02/13 - 09/17/13

09/06/13 - 09/17/13

10/28/13 - 12/11/13

12/02/13 - 12/12/13

Comments Received
(70)

Non-binding Poll
Results (74)

Ballot Results (73)

Summary (72)

Comments Received
(86)

Non-binding Poll
Results (91)

Ballot Results (90)

Summary (89)

Consideration of
Comments (75)

Consideration of
Comments (92)

BAL-002-2 (28)

BAL-001-2 (27)

Unofficial Comment Forms (Word)

Supporting Materials

Implementation Plan
Clean | Redline to Last Posting

BAL-013-1
Clean | Redline to Last Posting

Implementation Plan
Clean (25) | Redline to Last Posting
(26)

BAL-002-2
Clean (23) | Redline to Last Posting
(24)

Implementation Plan
Clean (21) | Redline to Last Posting
(22)

BAL-001-2
Clean (19) | Redline to Last Posting
(20)

Mapping Document
Clean (54) | Redline to Last Posting (55)

VRF/VSL Justification
Clean (52) | Redline to Last Posting (53)

Background Document
Clean (50) | Redline to Last Posting (51)

Supporting Materials

Clean (48) | Redline to Last Posting (49)

BAL-013-1

BAL-002-2

BAL-001-2

Submit Comments

Info (36)

Formal Comment Period

Vote

Info (41)

Initial Ballots and Non-binding Polls

Vote

03/12/13 - 04/25/13

04/16/13 - 04/25/13

BAL-013-1

BAL-002-2 (38)

BAL-001-2 (37)

Comments Received:

BAL-013-1

BAL-002-2 (45)

BAL-001-2 (44)

Non-binding Poll
Results:

BAL-001-2 (43) BAL013-1

BAL-002-2

Ballot Results:

Summary (42)

Ballot Results (58)

Summary (57)

BAL-002-2 (40)

BAL-001-2 (39)

Consideration of
Comments:

Vote
Formal Comment Period

Unofficial Comment Form (Word)

Background Document
Clean | Redline to Last Posting

Implementation Plan

Info

Supporting Materials

Info

Updated Info

Initial Ballot and Non-binding Poll

Join Ballot Pools

BAL-012-1
Clean | Redline to Last Posting

Draft 2

BAL-013-1

BAL-002-2 (35)

BAL-001-2 (34)

VRF/VSL Justification

BAL-002-2 (33)

BAL-001-2 (32)

Mapping Documents

BAL-013-1
Clean | Redline to Last Posting

BAL-002-2
Clean (31)

BAL-001-2
Clean (29) | Redline to Last Posting
(30)

Background Documents

BAL-013-1

11/30/2012 – 1/14/2013

1/4/2013 – 1/14/2013

03/12/13 - 04/10/13

Comments Received

Non-binding Poll
Results

Ballot Results

Summary

Mapping Document (6)

Implementation Plan (5)

Background Document (4)

BAL-002-1 (3)

Unofficial Comment Form (Word)
(2)

Supporting Materials

Draft 1
BAL-002-2
Clean (1)

VRF/VSL Justification (15)

Mapping Document (14)

Implementation Plan (13)

Background Document (12)

BAL-001-0.1a (11)

Unofficial Comment Form (Word)
(10)

Supporting Materials

BAL-001-1
Clean (9)

Draft 1

VRF/VSL Justification

Clean | Redline to Last Posting

Submit Comments
Comment Form - BAL-002-2

Info (7)

Formal Comment Period

Submit Comments
Comment Form - BAL-001-1

Info (16)

Formal Comment Period

Join Ballot Pool

Submit Comments

6/4/2012 -7/3/2012

6/4/2012 -7/3/2012

11/30/2012 – 1/3/2013

Comments Received
(8)

Comments Received
(17)

Consideration of
Comments (18)

Info
Submit Comments
Comment Form - BAL-013-1

Supporting Materials

Unofficial Comment Form (Word)

Implementation Plan

Background Document

Formal Comment Period

Submit Comments
Comment Form - BAL-012-1

Info

Formal Comment Period

BAL-013-1
Clean

Draft 1

Implementation Plan

Background Document

Unofficial Comment Form (Word)

Supporting Materials

BAL-012-1
Clean

Draft 1

6/4/2012 -7/3/2012

6/4/2012 - 7/3/2012

Comments Received

Comments Received

Consideration of
Comments

Standard BAL-002-2 – Contingency Reserve for Recovery from a Balancing Contingency Event
Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. The SAR for Project 2007-18, Reliability Based Controls, was posted for a 30-day formal
comment period on May 15, 2007.
2. A revised SAR for Project 2007-05, Reliability Based Controls, was posted for a second
30-day formal comment period on September 10, 2007.
3. The Standards Committee approved Project 2007-18, Reliability Based Controls, to be
moved to standard drafting on December 11, 2007.
4. The SAR for Project 2007-05, Balancing Authority Controls, was posted for a 30-day
formal comment period on July 3, 2007.
5. The Standards Committee approved Project 2007-05, Balancing Authority Controls, to
be moved to standard drafting on January 18, 2008.
6. The Standards Committee approved the merger of Project 2007-05, Balancing Authority
Controls, and Project 2007-18, Reliability-based Control, as Project 2010-14, Balancing
Authority Reliability-based Controls on July 28, 2010.
7. The NERC Standards Committee approved breaking Project 2010-14, Balancing
Authority Reliability-based Controls, into two phases and moving Phase 1 (Project 201014.1, Balancing Authority Reliability-based Controls – Reserves) into formal standards
development on July 13, 2011.
Proposed Action Plan and Description of Current Draft:
This is the first posting of the proposed new standard. This proposed draft standard will be
posted for a 30-day formal comment period beginning on June 4, 2012 through July 3, 2012.
Future Development Plan:
Anticipated Actions
1. Second posting

Anticipated Date
October/November
2012

2. Initial Ballot

November 2012

3. Third posting

March/April 2013

4. Successive ballot
5. Recirculation Ballot

BAL-002-2 Draft 1
June 4, 2012

May 2013
August 2013

Page 1 of 8

Standard BAL-002-2 – Contingency Reserve for Recovery from a Balancing Contingency Event
6. NERC BOT adoption.

BAL-002-2 Draft 1
June 4, 2012

September 2013

Page 2 of 8

Standard BAL-002-2 – Contingency Reserve for Recovery from a Balancing Contingency Event

Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Balancing Contingency Event: Any single event described in Subsections (A), (B), or (C) below,
or any series of such otherwise single events, with each separated from the next by less than
one minute.
A. Sudden Loss of Generation:
a. Due to
i. Unit tripping,
ii. Loss of generator Interconnection Facilities resulting in isolation of the
generator from the Bulk Electric System or from the responsible entity’s
electric system, or
iii. Sudden unplanned outage of transmission Facilities;
b. And, that causes an unexpected change to the responsible entity’s ACE;
c. Provided, however, that normal, recurring operating characteristics of a unit do
not constitute sudden or unanticipated losses and may not be subject to this
definition.
B. Sudden Loss of Non-Interruptible Import:
a. A sudden loss of a non-interruptible import, due to forced outage of
transmission equipment that causes an unexpected change to the responsible
entity’s ACE.
C. Unexpected Failure of Generation to Maintain or Increase:
a. Due to
i. Inability to start a unit the responsible entity planned to bring online at
that time (for reasons other than lack of fuel), or
ii. Internal plant equipment problems that force the generator to be
ramped down or taken offline;
b. And that, even if not an immediate cause of an unexpected change to the
responsible entity’s ACE, will, in the responsible entity’s judgment, leave the
responsible entity unable to maintain its ACE following the failure, unless it
deploys Contingency Reserve.
Most Severe Single Contingency (MSSC): The Balancing Contingency Event that would result in
the greatest loss (measured in MW) of generation output used by the Balancing Authority, or
the greatest loss of activated Direct Control Load Management used by the Balancing Authority,
to meet firm system load and non-interruptible export obligation (excluding export obligation
for which Contingency Reserve obligations are being met by the sink Balancing Authority).

BAL-002-2 Draft 1
June 4, 2012

Page 3 of 8

Standard BAL-002-2 – Contingency Reserve for Recovery from a Balancing Contingency Event
Reportable Contingency Event: Any Balancing Contingency Event greater than or equal to the
lesser amount of 80 percent of the Balancing Authority’s Most Severe Single Contingency or
500 MW.
Contingency Event Recovery Period: A period not exceeding 15 minutes following the start of
the Balancing Contingency Event. The start of the Balancing Contingency Event is the point in
time where the first change in MW is observed due to the event.
Contingency Reserve Restoration Period: A period not exceeding 90 minutes following the end
of the Contingency Event Recovery Period, during which the amount of Contingency Reserve
deployed to recover from a Balancing Contingency Event is to be restored.
Pre-Reportable Contingency Event ACE Value: The value of ACE immediately prior to a
Reportable Contingency Event when there are no previous Reportable Contingency Events for
which the Contingency Event Recovery Period is not yet completed,
or
The value of ACE that the Balancing Authority or Reserve Sharing Group must attain to fully
meet its ACE recovery requirement with respect to the immediately previous Reportable
Contingency Event for which the Contingency Event Recovery Period is not yet completed.

BAL-002-2 Draft 1
June 4, 2012

Page 4 of 8

Standard BAL-002-2 – Contingency Reserve for Recovery from a Balancing Contingency Event
A. Introduction
1.

Title:

Contingency Reserve for Recovery From a Balancing Contingency Event

2.

Number:

3.

Purpose: To ensure the Balancing Authority or Reserve Sharing Group utilizes its
Contingency Reserve to balance resources and demand and return the Balancing
Authority’s or Reserve Sharing Group’s Area Control Error to defined values (subject
to applicable limits) following a Reportable Contingency Event.

4.

Applicability:

BAL-002-2

4.1. Balancing Authority
4.2. Reserve Sharing Group
5.

(Proposed) Effective Date:
5.1. First day of the first calendar quarter that is six months beyond the date that this
standard is approved by applicable regulatory authorities, or in those
jurisdictions where regulatory approval is not required, the standard becomes
effective the first day of the first calendar quarter that is six months beyond the
date this standard is approved by the NERC Board of Trustees’, or as otherwise
made pursuant to the laws applicable to such ERO governmental authorities.

B. Requirements
R1.

Each Balancing Authority or Reserve Sharing Group experiencing a Reportable
Contingency Event shall implement its Contingency Reserve plan so that the Balancing
Authority or Reserve Sharing Group can demonstrate that, within the Contingency
Event Recovery Period: [Violation Risk Factor: ][Time Horizon: ]
x

x

The Balancing Authority or Reserve Sharing Group returned its ACE to:
o

Zero, less the sum of the magnitudes of all subsequent Balancing
Contingency Events that occur within the Contingency Event Recovery
Period, if its ACE just prior to the Reportable Contingency Event was positive
or equal to zero, Or

o

Its Pre-Reportable Contingency Event ACE Value, less the sum of the
magnitudes of all subsequent Balancing Contingency Events that occur within
the Contingency Event Recovery Period, if its ACE just prior to the Reportable
Contingency Event was negative.

Provided, however, that in either of the foregoing cases, if the Reportable
Contingency Event (individually or when combined with any previous Balancing
Contingency Events that have not completed their Contingency Reserve
Restoration Periods) exceeded the Balancing Authority’s or Reserve Sharing
Group’s Most Severe Single Contingency (MSSC), then the Balancing Authority or
Reserve Sharing Group need only demonstrate ACE recovery of at least equal to

BAL-002-2 Draft 1
June 4, 2012

Page 5 of 8

Standard BAL-002-2 – Contingency Reserve for Recovery from a Balancing Contingency Event
its MSSC, less the sum of the magnitudes of all Previous Balancing Contingency
Events that have not completed their Contingency Reserve Restoration Periods.
C. Measures
M1. Each Balancing Authority or Reserve Sharing Group shall have, and provide upon
request, evidence; such as computer logs or operator logs, with date and time of
occurrence to show compliance with Requirement R1.
D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
The regional entity is the Compliance Enforcement Authority, except where the
responsible entity works for the regional entity. Where the responsible entity
works for the regional entity, the regional entity will establish an agreement with
the ERO, or another entity approved by the ERO and FERC (i.e., another regional
entity), to be responsible for compliance enforcement.
1.2. Data 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 Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full-time period
since the last audit.
The Balancing Authority or Reserve Sharing Group shall retain data or evidence
to show compliance for the current year, plus three calendar years, unless
directed by its Compliance Enforcement Authority to retain specific evidence for
a longer period of time as part of an investigation.
If a Balancing Authority or Reserve Sharing Group is found noncompliant, it shall
keep information related to the noncompliance until found compliant, or for the
time period specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
subsequent requested and submitted records.
1.3. Compliance Monitoring and Assessment Processes
Compliance Audits
Self-Certifications
Spot Checking

BAL-002-2 Draft 1
June 4, 2012

Page 6 of 8

Standard BAL-002-2 – Contingency Reserve for Recovery from a Balancing Contingency Event
Compliance Investigations
Self-Reporting
Complaints
1.4. Additional Compliance Information
A Balancing Authority may elect to fulfill its Contingency Reserve obligations by
participating as a member of a Reserve Sharing Group.
A Balancing Authority or Reserve Sharing Group may use Contingency Reserve
for any Balancing Contingency Event.
A Balancing Authority or Reserve Sharing Group may optionally reduce the 80
percent threshold, upon written notification to the Regional Entity.
2.

Violation Severity Levels
R#

Lower VSL

Moderate VSL

High VSL

Severe VSL

R1
R2
R3
R4
E. Regional Variances
None.
F. Associated Documents
BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event
Background Document
Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0

August 8, 2005

Removed “Proposed” from Effective
Date

Errata

0

February 14,
2006

Revised graph on page 3, “10 min.” to
“Recovery time.” Removed fourth
bullet.

Errata

NERC BOT Adoption

Complete revision

2

BAL-002-2 Draft 1
June 4, 2012

Page 7 of 8

Standard BAL-002-2 – Contingency Reserve for Recovery from a Balancing Contingency Event

BAL-002-2 Draft 1
June 4, 2012

Page 8 of 8

Comment Form

Project 2010-14.1 Balancing Authority Reliability-based Control
BAL-002-2 í Contingency Reserve for Recovery from a Contingency Event

Please do not use this form to submit comments on the proposed revisions to BAL-002-2 Contingency
Reserve for Recovery from a Contingency Event. Comments must be submitted using the electronic
comment form by 8 p.m. July 3, 2012. If you have questions please contact Darrel Richardson (email)
or by telephone at (609) 613-1848.
Background Information:

Since loss of generation occurrences so often impacts all Balancing Authorities throughout an
Interconnection, BAL-002 was created to specify recovery actions and time frames. The original
Standards Authorization Request (SAR) approved by the Industry presumes there is presently sufficient
contingency reserve in all the North American Interconnections. The underlying goal of the SAR was to
update the Standard to make the measurement process more objective and to provide information to
the Balancing Authority or Reserve Sharing Group such that the parties would better understand the
use of contingency reserve to balance resources and demand following a Reportable Contingency
Event. The primary objective of BAL-002-2 is to measure the success of implementing a Contingency
Reserve Plan.

You do not have to answer all questions. Enter All Comments in Simple Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. The BARC SDT has developed five new terms to be used with this standard.
Balancing Contingency Event:
Any single event described in subsections (A), (B), or (C) below, or any series of such
otherwise single events with each separated from the next by less than one minute.
A. Sudden Loss of Generation:
a. Due to
i. unit tripping,
ii. loss of generator interconnection facilities resulting in isolation of the
generator from the Bulk Electric System or from the Responsible
Entity’s electric system, or
iii. sudden unplanned outage of transmission facilities;
b. And, that causes an unexpected change to the Responsible Entity’s ACE;
c. Provided, however, that normal, recurring operating characteristics of a unit
do not constitute sudden or unanticipated losses and may not be subject to
this definition.
B. Sudden Loss of Non-Interruptible Import:
a. A sudden loss of a non-interruptible import, due to forced outage of
transmission equipment, that causes an unexpected change to the
Responsible Entity’s ACE.
C. Unexpected Failure of Generation to Maintain or Increase:
a. Due to
i. inability to start a unit the Responsible Entity planned to bring online
at that time (for reasons other than lack of fuel), or
ii. internal plant equipment problems that force the generator to be
ramped down or taken offline;
b. And that, even if not an immediate cause of an unexpected change to the
Responsible Entity’s ACE, will, in the Responsible Entity’s judgment, leave
the Responsible Entity unable to maintain its ACE following the failure unless
it deploys contingency reserve.
Most Severe Single Contingency (MSSC):
The Balancing Contingency Event that would result in the greatest loss (measured in MW) of
generation output used by the Balancing Authority, or the greatest loss of activated Direct
Control Load Management used by the Balancing Authority, to meet firm system load and
non-interruptible export obligation (excluding export obligation for which contingency
reserve obligations are being met by the sink Balancing Authority).

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event
Comment Form

2

Reportable Contingency Event:
Any Balancing Contingency Event greater than or equal to the lesser amount of 80 percent
of the Balancing Authority’s Most Severe Single Contingency or 500 MW.
Contingency Event Recovery Period:
A period not exceeding 15 minutes following the start of the Balancing Contingency Event.
The start of the Balancing Contingency Event is the point in time where the first change in
MW is observed due to the event.
Contingency Reserve Restoration Period:
A period not exceeding 90 minutes following the end of the Contingency Event Recovery
Period, during which the Amount of Contingency Reserve deployed to recover from a
Balancing Contingency Event is to be restored.
Pre-Reportable Contingency Event ACE Value:
The value of ACE immediately prior to a Reportable Contingency Event when there are no
previous Reportable Contingency Events for which the Contingency Event Recovery Period
is not yet completed,
or
The value of ACE that the Balancing Authority or Reserve Sharing Group must attain to fully
meet its ACE recovery requirement with respect to the immediately previous Reportable
Contingency Event for which the Contingency Event Recovery Period is not yet completed.
Do you agree with the proposed definitions in this standard? If not, please explain in the comment
area below.
Yes
No
Comments:
2. The proposed Purpose Statement for the draft standard is:
To ensure the Balancing Authority or Reserve Sharing Group utilizes its Contingency Reserve to
balance resources and demand and return the Balancing Authority’s or Reserve Sharing Group’s
Area Control Error to defined values (subject to applicable limits) following a Reportable
Contingency Event.
Do you agree with this purpose statement? If not, please explain in the comment area below.
Yes
No
Comments:

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event
Comment Form

3

3. The BARC SDT has developed Requirement R1 to determine whether a Balancing Authority (BA)
or Reserve Sharing Group (RSG) has implemented its Contingency Reserve plan and determine
whether a BA or RSG met ACE recovery equal to the BA’s or RSG’s Most Severe Single
Contingency.
R1. Each Balancing Authority or Reserve Sharing Group experiencing a Reportable Contingency
Event shall implement its Contingency Reserve plan so that the Balancing Authority or Reserve
Sharing Group can demonstrate that, within the Contingency Event Recovery Period:
x

ͻ

The Balancing authority or Reserve Sharing Group returned its ACE to
ƒ

Zero, less the sum of the magnitudes of all subsequent Balancing
Contingency Events that occur within the Contingency Event Recovery
Period, if its ACE just prior to the Reportable Contingency Event was positive
or equal to zero, or

ƒ

Its Pre-Reportable Contingency Event ACE Value, less the sum of the
magnitudes of all subsequent Balancing Contingency Events that occur within
the Contingency Event Recovery Period, if its ACE just prior to the Reportable
Contingency Event was negative.

Provided, however, that in either of the foregoing cases, if the Reportable
Contingency Event (individually or when combined with any previous Balancing
Contingency Events that have not completed their Contingency Reserve Restoration
Periods) exceeded the Balancing Authority’s or Reserve Sharing Group’s Most Severe
Single Contingency (MSSC), then the Balancing Authority or Reserve Sharing Group
need only demonstrate ACE recovery of at least equal to its MSSC, less the sum of
the magnitudes of all Previous Balancing Contingency Events that have not
completed their Contingency Reserve Restoration Periods.

Do you agree with this Requirement? If not, please explain in the comment area below.
Yes
No
Comments:
4. The BARC SDT has developed a Measure for the proposed Requirement within this standard.
Do you agree with the proposed Measure in this standard? If not, please explain in the
comment area.
Yes
No
Comments:

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event
Comment Form

4

5. The BARC SDT has developed a document “BAL-002-2 Contingency Reserve for Recovery from a
Balancing Contingency Event Standard Background Document” which provides information
behind the development of the standard. Do you agree that this new document provides
sufficient clarity as to the development of the standard? If not, please explain in the comment
area.
Yes
No
Comments:
6. If you are aware of any conflicts between the proposed standard and any regulatory function,
rule order, tariff, rate schedule, legislative requirement, or agreement please identify the
conflict here.
Comments:
7. Do you have any other comment on BAL-002-2, not expressed in the questions above, for the
BARC SDT?
Comments:

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event
Comment Form

5

Standard BAL-002-1 — Disturbance Control Performance
A.

B.

Introduction
1.

Title:

Disturbance Control Performance

2.
3.

Number: BAL-002-1
Purpose: The purpose of the Disturbance Control Standard (DCS) is to ensure the
Balancing Authority is able to utilize its Contingency Reserve to balance resources and
demand and return Interconnection frequency within defined limits following a Reportable
Disturbance. Because generator failures are far more common than significant losses of load
and because Contingency Reserve activation does not typically apply to the loss of load, the
application of DCS is limited to the loss of supply and does not apply to the loss of load.

4.

Applicability:
4.1. Balancing Authorities
4.2. Reserve Sharing Groups (Balancing Authorities may meet the requirements of
Standard 002 through participation in a Reserve Sharing Group.)
4.3. Regional Reliability Organizations

5.

(Proposed) Effective Date: The first day of the first calendar quarter, one year after
applicable regulatory approval; or in those jurisdictions where no regulatory approval is
required, the first day of the first calendar quarter one year after Board of Trustees’ adoption.

Requirements
R1. Each Balancing Authority shall have access to and/or operate Contingency Reserve to respond
to Disturbances. Contingency Reserve may be supplied from generation, controllable load
resources, or coordinated adjustments to Interchange Schedules.
R1.1. A Balancing Authority may elect to fulfill its Contingency Reserve obligations by
participating as a member of a Reserve Sharing Group. In such cases, the Reserve
Sharing Group shall have the same responsibilities and obligations as each Balancing
Authority with respect to monitoring and meeting the requirements of Standard BAL002.
R2. Each Regional Reliability Organization, sub-Regional Reliability Organization or Reserve
Sharing Group shall specify its Contingency Reserve policies, including:
R2.1. The minimum reserve requirement for the group.
R2.2. Its allocation among members.
R2.3. The permissible mix of Operating Reserve – Spinning and Operating Reserve –
Supplemental that may be included in Contingency Reserve.
R2.4. The procedure for applying Contingency Reserve in practice.
R2.5. The limitations, if any, upon the amount of interruptible load that may be included.
R2.6. The same portion of resource capacity (e.g. reserves from jointly owned generation)
shall not be counted more than once as Contingency Reserve by multiple Balancing
Authorities.
R3. Each Balancing Authority or Reserve Sharing Group shall activate sufficient Contingency
Reserve to comply with the DCS.
R3.1. As a minimum, the Balancing Authority or Reserve Sharing Group shall carry at least
enough Contingency Reserve to cover the most severe single contingency. All
Balancing Authorities and Reserve Sharing Groups shall review, no less frequently

Adopted by Board of Trustees: August 5, 2010

1

Standard BAL-002-1 — Disturbance Control Performance
than annually, their probable contingencies to determine their prospective most severe
single contingencies.
R4. A Balancing Authority or Reserve Sharing Group shall meet the Disturbance Recovery
Criterion within the Disturbance Recovery Period for 100% of Reportable Disturbances. The
Disturbance Recovery Criterion is:
R4.1. A Balancing Authority shall return its ACE to zero if its ACE just prior to the
Reportable Disturbance was positive or equal to zero. For negative initial ACE values
just prior to the Disturbance, the Balancing Authority shall return ACE to its preDisturbance value.
R4.2. The default Disturbance Recovery Period is 15 minutes after the start of a Reportable
Disturbance.
R5. Each Reserve Sharing Group shall comply with the DCS. A Reserve Sharing Group shall be
considered in a Reportable Disturbance condition whenever a group member has experienced
a Reportable Disturbance and calls for the activation of Contingency Reserves from one or
more other group members. (If a group member has experienced a Reportable Disturbance
but does not call for reserve activation from other members of the Reserve Sharing Group,
then that member shall report as a single Balancing Authority.) Compliance may be
demonstrated by either of the following two methods:
R5.1. The Reserve Sharing Group reviews group ACE (or equivalent) and demonstrates
compliance to the DCS. To be in compliance, the group ACE (or its equivalent) must
meet the Disturbance Recovery Criterion after the schedule change(s) related to reserve
sharing have been fully implemented, and within the Disturbance Recovery Period.
or
R5.2. The Reserve Sharing Group reviews each member’s ACE in response to the activation
of reserves. To be in compliance, a member’s ACE (or its equivalent) must meet the
Disturbance Recovery Criterion after the schedule change(s) related to reserve sharing
have been fully implemented, and within the Disturbance Recovery Period.
R6. A Balancing Authority or Reserve Sharing Group shall fully restore its Contingency Reserves
within the Contingency Reserve Restoration Period for its Interconnection.
R6.1. The Contingency Reserve Restoration Period begins at the end of the Disturbance
Recovery Period.
R6.2. The default Contingency Reserve Restoration Period is 90 minutes.
C.

Measures
M1. A Balancing Authority or Reserve Sharing Group shall calculate and report compliance with
the Disturbance Control Standard for all Disturbances greater than or equal to 80% of the
magnitude of the Balancing Authority’s or of the Reserve Sharing Group’s most severe single
contingency loss. Regions may, at their discretion, require a lower reporting threshold.
Disturbance Control Standard is measured as the percentage recovery (Ri).
For loss of generation:
if ACEA < 0
then

Adopted by Board of Trustees: August 5, 2010

2

Standard BAL-002-1 — Disturbance Control Performance

Ri

MWLoss  max(0, ACE A  ACEM )
* 100%
MWLoss

if ACEA > 0
then

Ri

MW Loss  max(0, ACE M )
* 100%
MW Loss

where:
x MWLOSS is the MW size of the Disturbance as
measured at the beginning of the loss,
x ACEA is the pre-disturbance ACE,
x ACEM is the maximum algebraic value of ACE measured within the fifteen minutes
following the Disturbance. A Balancing Authority or Reserve Sharing Group may, at
its discretion, set ACEM = ACE15 min, and
The Balancing Authority or Reserve Sharing Group shall record the MWLOSS value as
measured at the site of the loss to the extent possible. The value should not be measured as a
change in ACE since governor response and AGC response may introduce error.
The Balancing Authority or Reserve Sharing Group shall base the value for ACEA on the
average ACE over the period just prior to the start of the Disturbance (10 and 60 seconds prior
and including at least 4 scans of ACE). In the illustration below, the horizontal line represents
an averaging of ACE for 15 seconds prior to the start of the Disturbance with a result of ACEA
= - 25 MW.

ACE
-30

-20

-10

0

0

-40

-80

The average percent recovery is the arithmetic average of all the calculated Ri’s for Reportable
Disturbances during a given quarter. Average percent recovery is similarly calculated for
excludable Disturbances.
D.

Compliance
1.

Compliance Monitoring Process

Adopted by Board of Trustees: August 5, 2010

3

Standard BAL-002-1 — Disturbance Control Performance
Compliance with the DCS shall be measured on a percentage basis as set forth in the measures
above.
Each Balancing Authority or Reserve Sharing Group shall submit one completed copy of DCS
Form, “NERC Control Performance Standard Survey – All Interconnections” to its Resources
Subcommittee Survey Contact no later than the 10th day following the end of the calendar
quarter (i.e. April 10th, July 10th, October 10th, January 10th). The Regional Entity must
submit a summary document reporting compliance with DCS to NERC no later than the 20th
day of the month following the end of the quarter.
1.1.

Compliance Enforcement Authority
Regional Entity.

1.2.

Compliance Monitoring Period and Reset Timeframe
Compliance for DCS will be evaluated for each reporting period. Reset is one calendar
quarter without a violation.

1.3.

Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints

1.4.

Data Retention
The data that support the calculation of DCS are to be retained in electronic form for at
least a one-year period. If the DCS data for a Reserve Sharing Group and Balancing
Area are undergoing a review to address a question that has been raised regarding the
data, the data are to be saved beyond the normal retention period until the question is
formally resolved.

1.5.

Additional Compliance Information
Reportable Disturbances – Reportable Disturbances are contingencies that are greater
than or equal to 80% of the most severe single Contingency. A Regional Reliability
Organization, sub-Regional Reliability Organization or Reserve Sharing Group may
optionally reduce the 80% threshold, provided that normal operating characteristics are
not being considered or misrepresented as contingencies. Normal operating
characteristics are excluded because DCS only measures the recovery from sudden,
unanticipated losses of supply-side resources.
Simultaneous Contingencies – Multiple Contingencies occurring within one minute
or less of each other shall be treated as a single Contingency. If the combined
magnitude of the multiple Contingencies exceeds the most severe single Contingency,
the loss shall be reported, but excluded from compliance evaluation.
Multiple Contingencies within the Reportable Disturbance Period – Additional
Contingencies that occur after one minute of the start of a Reportable Disturbance but
before the end of the Disturbance Recovery Period can be excluded from evaluation.
The Balancing Authority or Reserve Sharing Group shall determine the DCS
compliance of the initial Reportable Disturbance by performing a reasonable

Adopted by Board of Trustees: August 5, 2010

4

Standard BAL-002-1 — Disturbance Control Performance
estimation of the response that would have occurred had the second and subsequent
contingencies not occurred.
Multiple Contingencies within the Contingency Reserve Restoration Period –
Additional Reportable Disturbances that occur after the end of the Disturbance
Recovery Period but before the end of the Contingency Reserve Restoration Period
shall be reported and included in the compliance evaluation. However, the Balancing
Authority or Reserve Sharing Group can request a waiver from the Resources
Subcommittee for the event if the contingency reserves were rendered inadequate by
prior contingencies and a good faith effort to replace contingency reserve can be
shown.
2.

Levels of Non-Compliance
Each Balancing Authority or Reserve Sharing Group not meeting the DCS during a given
calendar quarter shall increase its Contingency Reserve obligation for the calendar quarter
(offset by one month) following the evaluation by the NERC or Compliance Monitor [e.g. for
the first calendar quarter of the year, the penalty is applied for May, June, and July.] The
increase shall be directly proportional to the non-compliance with the DCS in the preceding
quarter. This adjustment is not compounded across quarters, and is an additional percentage
of reserve needed beyond the most severe single Contingency. A Reserve Sharing Group may
choose an allocation method for increasing its Contingency Reserve for the Reserve Sharing
Group provided that this increase is fully allocated.
A representative from each Balancing Authority or Reserve Sharing Group that was noncompliant in the calendar quarter most recently completed shall provide written
documentation verifying that the Balancing Authority or Reserve Sharing Group will apply
the appropriate DCS performance adjustment beginning the first day of the succeeding month,
and will continue to apply it for three months. The written documentation shall accompany
the quarterly Disturbance Control Standard Report when a Balancing Authority or Reserve
Sharing Group is non-compliant.

3.
E.

Violation Severity Levels (no changes)

Regional Differences
None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0

August 8, 2005

Removed “Proposed” from Effective Date

Errata

0

February 14,
2006

Revised graph on page 3, “10 min.” to
“Recovery time.” Removed fourth bullet.

Errata

1

TBD

Modified to address Order No. 693
Directives contained in paragraph 321.

Revised.

Adopted by Board of Trustees: August 5, 2010

5

BAL-0 0 2 -2 – Co n t in g e n cy
Re s e rve fo r Re co ve ry fro m a
Ba la n cin g Co n t in g e n cy Eve n t
St a n d a rd Ba ckg r o u n d
Do cu m e n t
January 2012

3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Table of Contents

Table of Contents

Contents
Table of Contents ............................................................................................................................ 2
Introduction .................................................................................................................................... 3
Background and Rationale by Requirement ................................................................................... 3
Requirement 1 ............................................................................................................................ 3

BAL-002-2 - Background Document
June 4, 2012

2

Contingency Reserve for Recovery From a Balancing Contingency Event Standard Background
Document

Introduction
Since loss of generation occurs so often and impacts all Balancing Authorities throughout an
Interconnection, BAL-002 was created to specify recovery actions and associated timeframes.
This document provides background on the development and implementation of BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event. This document explains
the rationale and considerations for the requirements and their associated compliance
information. The original Standards Authorization Request (SAR), approved by the industry,
presumes there is presently sufficient contingency reserve in all the North American
Interconnections. The underlying goal of the SAR was to update the standard to make the
measurement process more objective and to provide information to the Balancing Authority or
Reserve Sharing Group, such that the parties would better understand the use of Contingency
Reserve to balance resources and demand following a Reportable Contingency Event. The
primary objective of BAL-002-2 is to measure the success of implementing a Contingency
Reserve plan.

Background and Rationale by Requirement
Requirement 1
R1. Each Balancing Authority or Reserve Sharing Group experiencing a Reportable
Contingency Event shall implement its Contingency Reserve plan so that the Balancing
Authority or Reserve Sharing Group can demonstrate that, within the Contingency
Recovery period:
x

The Balancing Authority or Reserve Sharing Group returned its ACE to:
o Zero, less the sum of the magnitudes of all subsequent Balancing
Contingency Events that occur within the Contingency Event Recovery
Period, if its ACE just prior to the Reportable Contingency Event was positive
or equal to zero, or
o Its Pre-Reportable Contingency Event ACE Value, less the sum of the
magnitudes of all subsequent Balancing Contingency Events that occur within
the Contingency Event Recovery Period, if its ACE just prior to the Reportable
Contingency Event was negative.

x

Provided, however, that in either of the foregoing cases, if the Reportable
Contingency Event (individually or when combined with any previous Balancing
Contingency Events that have not completed their Contingency Reserve
Restoration Periods) exceeded the Balancing Authority’s or Reserve Sharing
Group’s Most Severe Single Contingency (MSSC), then the Balancing Authority or

BAL-002-2 - Background Document
June 4, 2012

3

Contingency Reserve for Recovery From a Balancing Contingency Event Standard Background
Document
Reserve Sharing Group need only demonstrate ACE recovery of at least equal to
its MSSC, less the sum of the magnitudes of all previous Balancing Contingency
Events that have not completed their Contingency Reserve Restoration Periods.
Background and Rationale
This requirement reflects the operating principles first established by NERC Policy 1. Its
objective is to measure the successful implementation of the Contingency Reserve Plan for
Reportable Contingency Events. It requires the Balancing Authority to have Contingency
Reserve available to recover from events that would be less than or equal to the Balancing
Authority’s MSSC. It establishes a ceiling for the amount of Contingency Reserve and
timeframe the BA or RSG must demonstrate for compliancy evaluation. It is intended to
eliminate the ambiguities and questions associated with the existing standard. In addition, it
allows BAs and RSGs to have clear way to show compliance and support the Interconnection to
full extent of MSSC.

BAL-002-2 - Background Document
June 4, 2012

4

Implementation Plan

Project 2010-14.1 Balancing Authority Reliability-based Controls
- Reserves
Implementation Plan for BAL-002-2 – Contingency Reserve for Recovery from a Balancing
Contingency Event
Approvals Required
BAL-002-2 – Contingency Reserve for Recovery from a Balancing Contingency Event
Prerequisite Approvals
None
Revisions to Glossary Terms
The following definitions shall become effective when BAL-002-2 becomes effective:
Balancing Contingency Event: Any single event described in Subsections (A), (B), or (C) below, or
any series of such otherwise single events with each separated from the next by less than one
minute.
A. Sudden Loss of Generation:
a. Due to
i. unit tripping,
ii. loss of generator Interconnection Facilities resulting in isolation of the
generator from the Bulk Electric System or from the responsible entity’s
electric system, or
iii. sudden unplanned outage of transmission Facilities;
b. And that causes an unexpected change to the responsible entity’s ACE;
c. Provided, however, that normal, recurring operating characteristics of a unit do not
constitute sudden or unanticipated losses and may not be subject to this definition.
B. Sudden Loss of Non-Interruptible Import:
a. A sudden loss of a non-interruptible import, due to forced outage of transmission
equipment, that causes an unexpected change to the responsible entity’s ACE.
C. Unexpected Failure of Generation to Maintain or Increase:
a. Due to

i. Inability to start a unit the responsible entity planned to bring online at that
time (for reasons other than lack of fuel), or
ii. Internal plant equipment problems that force the generator to be ramped
down or taken offline;
b. And that, even if not an immediate cause of an unexpected change to the
responsible entity’s ACE, will, in the responsible entity’s judgment, leave the
responsible entity unable to maintain its ACE following the failure unless it deploys
Contingency Reserve.
Most Severe Single Contingency (MSSC): The Balancing Contingency Event that would result in the
greatest loss (measured in MW) of generation output used by the Balancing Authority, or the
greatest loss of activated Direct Control Load Management used by the Balancing Authority to
meet firm System Load and non-interruptible export obligation (excluding export obligation for
which Contingency Reserve obligations are being met by the sink Balancing Authority).
Reportable Contingency Event: Any Balancing Contingency Event greater than or equal to the
lesser amount of 80 percent of the Balancing Authority’s Most Severe Single Contingency, or 500
MW.
Contingency Event Recovery Period: A period not exceeding 15 minutes following the start of the
Balancing Contingency Event. The start of the Balancing Contingency Event is the point in time
where the first change in MW is observed due to the event.
Contingency Reserve Restoration Period: A period not exceeding 90 minutes following the end of
the Contingency Event Recovery Period, during which the amount of Contingency Reserve
deployed to recover from a Balancing Contingency Event is to be restored.
Pre-Reportable Contingency Event ACE Value: The value of ACE immediately prior to a Reportable
Contingency Event when there are no previous Reportable Contingency Events for which the
Contingency Event Recovery Period is not yet completed,
or
The value of ACE that the Balancing Authority or Reserve Sharing Group must attain to fully meet
its ACE recovery requirement with respect to the immediately previous Reportable Contingency
Event for which the Contingency Event Recovery Period is not yet completed.

Applicable Entities
Balancing Authority
Reserve Sharing Group
Applicable Facilities

BAL-002-2 – Contingency Reserve for Recovery from a Balancing Contingency Event
June 4, 2012

2

N/A
Conforming Changes to Other Standards
None
Effective Dates
BAL-002-2 shall become effective as follows:
First day of the first calendar quarter that is six months beyond the date that this standard is
approved by applicable regulatory authorities, or in those jurisdictions where regulatory
approval is not required, the standard becomes effective the first day of the first calendar
quarter that is six months beyond the date this standard is approved by the NERC Board of
Trustees’, or as otherwise made pursuant to the laws applicable to such ERO governmental
authorities.
Justification
The six-month period for implementation of BAL-002-2 will provide ample time for Balancing
Authorities to make necessary modifications to existing software programs to ensure compliance.
Retirements
BAL-002-0, Disturbance Control Performance, and BAL-002-1, Disturbance Control Performance should
be retired at midnight of the day immediately prior to the Effective Date of BAL-002-2 in the particular
jurisdiction in which the new standard is becoming effective.

BAL-002-2 – Contingency Reserve for Recovery from a Balancing Contingency Event
June 4, 2012

3

R1.1. A Balancing Authority may
elect to fulfill its Contingency
Reserve obligations by
participating as a member of a
Reserve Sharing Group. In such
cases, the Reserve Sharing Group
shall have the same

Standard BAL-002-0
NERC Board Approved
R1.
Each Balancing Authority shall
have access to and/or operate
Contingency Reserve to respond to
Disturbances. Contingency Reserve may
be supplied from generation,
controllable load resources, or
coordinated adjustments to Interchange
Schedules.
This Requirement has been
moved into BAL-002-2
“Additional Compliance
Information”
1.4.

A Balancing Authority or Reserve Sharing Group
may use Contingency Reserve for any Balancing
Contingency Event.

A Balancing Authority may elect to fulfill its
Contingency Reserve obligations by participating
as a member of a Reserve Sharing Group.

Additional Compliance Information

BAL-002-0 Mapping to Proposed NERC Reliability Standard BAL-002-2
Comment
Proposed Standard BAL-002-2

Project 2010-14.1 Balancing Authority Reliability-based
Controls - Reserves
BAL-002-2 Contingency Reserve for Recovery from a
Balancing Contingency Event Mapping Document

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event
June 4, 2012

R2.3. The permissible mix of

R2.2. Its allocation among
members.

R2.1. The minimum reserve
requirement for the group.

Standard BAL-002-0
NERC Board Approved
responsibilities and obligations as
each Balancing Authority with
respect to monitoring and
meeting the requirements of
Standard BAL-002.The Reliability
Coordinator and Planning
Authority shall each establish a
set of inter-regional and intraregional Transfer Capabilities
that is consistent with its current
Transfer Capability Methodology.
R2. Each Regional Reliability
This Requirement has been
Organization, sub-Regional
moved into BAL-012-0
Reliability Organization or Reserve
Requirements R2 and R4
Sharing Group shall specify its
Contingency Reserve policies,
including:

2

2.1. The determination of the Balancing Authority’s
or Reserve Sharing Group’s Contingency Reserve
margin.

R2. Each Balancing Authority and Reserve Sharing
Group shall, once each calendar year with no more
that 15 calendar months between intervals, document
its annual plan for Contingency Reserve used to
recover from Balancing Contingency Events addressing
each of the following: [Violation Risk Factor:] [Time
Horizon: ]

Requirement R2

BAL-012-0

BAL-002-0 Mapping to Proposed NERC Reliability Standard BAL-002-2
Comment
Proposed Standard BAL-002-2

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event
June 4, 2012

R2.6. The same portion of resource
capacity (e.g. reserves from
jointly owned generation)
shall not be counted more
than once as Contingency
Reserve by multiple Balancing
Authorities.

R2.5. The limitations, if any, upon
the amount of interruptible
load that may be included.

R2.4. The procedure for applying
Contingency Reserve in
practice.

Standard BAL-002-0
NERC Board Approved
Operating Reserve – Spinning
and Operating Reserve –
Supplemental that may be
included in Contingency
Reserve.

3

2.6. The characteristics: such as capabilities,
constraints and volatilities, of the Load operating

2.5. The characteristics: such as capabilities,
constraints and volatilities, of the resources
operating inside the Balancing Authority Area.

2.4. The incorporation of energy import and export
schedules by entities within the Balancing
Authority Area and with other Balancing
Authorities.

2.3. The control of supply and demand resources
such as generators, controllable Loads and energy
storage devices.

2.2.3. Events associated with Energy
Emergency Alert 3.

2.2.2. Events associated with Energy
Emergency Alert 2, and

2.2.1. Balancing Contingency Event

2.2. The types of resources and the portion of their
capacity capable of reducing the Balancing
Authority’s Area Control Error in response to each
of the following

BAL-002-0 Mapping to Proposed NERC Reliability Standard BAL-002-2
Comment
Proposed Standard BAL-002-2

Each Balancing Authority or
Reserve Sharing Group shall

This Requirement has been
moved into BAL-002-2
Requirements R1 and BAL-

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event
June 4, 2012

R3.

Standard BAL-002-0
NERC Board Approved

Requirement R1

BAL-002-2

4.4. Reporting and record keeping processes

4.3. The procedure for activating reserves

4.2. Allocation of reserves among members

4.1. The minimum reserve requirement for the
group

R4. Each Reserve Sharing Group or Frequency
Response Sharing Group shall have a signed
agreement among the participating Balancing
Authorities addressing each of the following:

Requirement R4

4

2.8. The amount of the Balancing Authority’s or
Reserve Sharing Group’s resources that can be
reduced in response to a Large Loss of Load Event.

2.7. The exclusion of any portion of shared
contingency resources included in another
Balancing Authority’s Regulating, Contingency, or
Frequency Responsive Reserve plans.

inside the Balancing Authority Area.

BAL-002-0 Mapping to Proposed NERC Reliability Standard BAL-002-2
Comment
Proposed Standard BAL-002-2

012-0 Requirement R2

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event
June 4, 2012

R3.1. As a minimum, the Balancing
Authority or Reserve
Sharing Group shall carry at
least enough Contingency
Reserve to cover the most
severe single contingency.
All Balancing Authorities
and Reserve Sharing Groups
shall review, no less
frequently than annually,
their probable
contingencies to determine
their prospective most
severe single contingencies.

Standard BAL-002-0
NERC Board Approved
activate sufficient Contingency
Reserve to comply with the DCS.

x

x

Provided, however, that in either of the foregoing
cases, if the Reportable contingency Event
(individually or when combined with any previous

5

o Its Pre-Reportable Contingency Event ACE
Value, less the sum of the magnitudes of all
subsequent Balancing Contingency Events that
occur within the Contingency Event Recovery
Period, if its ACE just prior to the Reportable
Contingency Event was negative.

o Zero, less the sum of the magnitudes of all
subsequent Balancing Contingency Events that
occur within the Contingency Event Recovery
Period, if its ACE just prior to the Reportable
Contingency Event was positive or equal to
zero, or

The Balancing Authority or Reserve Sharing Group
returned its ACE to:

Each Balancing Authority or Reserve Sharing Group
experiencing a Reportable Contingency Event shall
implement its Contingency Reserve plan so that the
Balancing authority or Reserve Sharing Group can
demonstrate that, within the Contingency Event Recovery
Period:

BAL-002-0 Mapping to Proposed NERC Reliability Standard BAL-002-2
Comment
Proposed Standard BAL-002-2

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event
June 4, 2012

Standard BAL-002-0
NERC Board Approved

6

2.1. The determination of the Balancing Authority’s
or Reserve Sharing Group’s Contingency Reserve

R2. Each Balancing Authority and Reserve Sharing
Group shall, once each calendar year with no more
that 15 calendar months between intervals, document
its annual plan for Contingency Reserve used to
recover from Balancing Contingency Events addressing
each of the following: [Violation Risk Factor:] [Time
Horizon: ]

Requirement R2

BAL-012-0

Balancing Contingency Events that have not
completed their Contingency Reserve Restoration
Periods) exceeded the Balancing Authority’s or
Reserve Sharing Group’s Most Severe Single
contingency (MSSC), then the Balancing Authority or
Reserve Sharing Group need only demonstrate ACE
recovery of at least equal to its MSSC, less the sum
of the magnitudes of all Previous Balancing
Contingency Events that have not completed their
Contingency Reserve Restoration Periods.

BAL-002-0 Mapping to Proposed NERC Reliability Standard BAL-002-2
Comment
Proposed Standard BAL-002-2

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event
June 4, 2012

Standard BAL-002-0
NERC Board Approved

2.6. The characteristics: such as capabilities,

2.5. The characteristics: such as capabilities,
constraints and volatilities, of the resources
operating inside the Balancing Authority Area.

7

2.4. The incorporation of energy import and export
schedules by entities within the Balancing
Authority Area and with other Balancing
Authorities.

2.3. The control of supply and demand resources
such as generators, controllable Loads and energy
storage devices.

2.2.3. Events associated with Energy
Emergency Alert 3.

2.2.2. Events associated with Energy
Emergency Alert 2, and

2.2.1. Balancing Contingency Event

2.2. The types of resources and the portion of their
capacity capable of reducing the Balancing
Authority’s Area Control Error in response to each
of the following

margin.

BAL-002-0 Mapping to Proposed NERC Reliability Standard BAL-002-2
Comment
Proposed Standard BAL-002-2

R4.1. A Balancing Authority shall
return its ACE to zero if its
ACE just prior to the
Reportable Disturbance was
positive or equal to zero.

A Balancing Authority or Reserve
Sharing Group shall meet the
Disturbance Recovery Criterion
within the Disturbance Recovery
Period for 100% of Reportable
Disturbances. The Disturbance
Recovery Criterion is:

This Requirement has been
moved into BAL-002-2
Requirement R1 and into the
“Contingency Event Recovery
Period” definition

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event
June 4, 2012

R4.

Standard BAL-002-0
NERC Board Approved

x

8

o Zero, less the sum of the magnitudes of all
subsequent Balancing Contingency Events that
occur within the Contingency Event Recovery

The Balancing Authority or Reserve Sharing Group
returned its ACE to:

Each Balancing Authority or Reserve Sharing Group
experiencing a Reportable Contingency Event shall
implement its Contingency Reserve plan so that the
Balancing authority or Reserve Sharing Group can
demonstrate that, within the Contingency Event
Recovery Period:

Requirement R1

BAL-002-0 Requirement R4 and R4.1 to BAL-002-2

2.8. The amount of the Balancing Authority’s or
Reserve Sharing Group’s resources that can be
reduced in response to a Large Loss of Load Event.

2.7. The exclusion of any portion of shared
contingency resources included in another
Balancing Authority’s Regulating, Contingency, or
Frequency Responsive Reserve plans.

constraints and volatilities, of the Load operating
inside the Balancing Authority Area.

BAL-002-0 Mapping to Proposed NERC Reliability Standard BAL-002-2
Comment
Proposed Standard BAL-002-2

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event
June 4, 2012

R4.2. The default Disturbance
Recovery Period is 15
minutes after the start of a
Reportable Disturbance.
Each Balancing Authority
shall have access to and/or
operate Contingency
Reserve to respond to
Disturbances. Contingency
Reserve may be supplied
from generation,
controllable load resources,
or coordinated adjustments
to Interchange Schedules.

Standard BAL-002-0
NERC Board Approved
For negative initial ACE
values just prior to the
Disturbance, the Balancing
Authority shall return ACE
to its pre-Disturbance value.

9

Provided, however, that in either of the foregoing
cases, if the Reportable contingency Event
(individually or when combined with any previous
Balancing Contingency Events that have not
completed their Contingency Reserve Restoration
Periods) exceeded the Balancing Authority’s or
Reserve Sharing Group’s Most Severe Single
contingency (MSSC), then the Balancing Authority or
Reserve Sharing Group need only demonstrate ACE
recovery of at least equal to its MSSC, less the sum
of the magnitudes of all Previous Balancing
Contingency Events that have not completed their
Contingency Reserve Restoration Periods.
BAL-002-0 Requirement R4.2 to “Contingency Event Recovery

x

o Its Pre-Reportable Contingency Event ACE
Value, less the sum of the magnitudes of all
subsequent Balancing Contingency Events that
occur within the Contingency Event Recovery
Period, if its ACE just prior to the Reportable
Contingency Event was negative.

Period, if its ACE just prior to the Reportable
Contingency Event was positive or equal to
zero, or

BAL-002-0 Mapping to Proposed NERC Reliability Standard BAL-002-2
Comment
Proposed Standard BAL-002-2

This Requirement has been
moved into BAL-002-2
Requirement R1 and BAL012-0 Requirement R4

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event
June 4, 2012

R5.
Each Reserve Sharing Group shall
comply with the DCS. A Reserve Sharing
Group shall be considered in a
Reportable Disturbance condition
whenever a group member has
experienced a Reportable Disturbance
and calls for the activation of
Contingency Reserves from one or more

Standard BAL-002-0
NERC Board Approved

Each Balancing Authority or Reserve Sharing Group
experiencing a Reportable Contingency Event shall
implement its Contingency Reserve plan so that the
Balancing authority or Reserve Sharing Group can
demonstrate that, within the Contingency Event

Requirement R1

BAL-002-2

following the start of the Balancing Contingency
Event.

10

A period not exceeding 90 minutes following the end of
the Contingency Event Recovery Period, during which
the amount of Contingency Reserve deployed to
recover from a Balancing Contingency Event is to be
restored. A period not exceeding 15 minutes

Contingency Reserve Restoration Period:

A period not exceeding 15 minutes following the start
of the Balancing Contingency Event. The start of the
Balancing Contingency Event is the point in time where
the first change in MW is observed due to the event.

Contingency Event Recovery Period

Period” and “Contingency Event Restoration Period” definitions.

BAL-002-0 Mapping to Proposed NERC Reliability Standard BAL-002-2
Comment
Proposed Standard BAL-002-2

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event
June 4, 2012

or

R5.1. The Reserve Sharing Group
reviews group ACE (or
equivalent) and demonstrates
compliance to the DCS. To be in
compliance, the group ACE (or its
equivalent) must meet the
Disturbance Recovery Criterion
after the schedule change(s)
related to reserve sharing have
been fully implemented, and
within the Disturbance Recovery
Period.

Standard BAL-002-0
NERC Board Approved
other group members. (If a group
member has experienced a Reportable
Disturbance but does not call for reserve
activation from other members of the
Reserve Sharing Group, then that
member shall report as a single
Balancing Authority.) Compliance may
be demonstrated by either of the
following two methods:

x

x

11

Provided, however, that in either of the foregoing
cases, if the Reportable contingency Event
(individually or when combined with any previous
Balancing Contingency Events that have not
completed their Contingency Reserve Restoration
Periods) exceeded the Balancing Authority’s or
Reserve Sharing Group’s Most Severe Single
contingency (MSSC), then the Balancing Authority or

o Its Pre-Reportable Contingency Event ACE
Value, less the sum of the magnitudes of all
subsequent Balancing Contingency Events that
occur within the Contingency Event Recovery
Period, if its ACE just prior to the Reportable
Contingency Event was negative.

o Zero, less the sum of the magnitudes of all
subsequent Balancing Contingency Events that
occur within the Contingency Event Recovery
Period, if its ACE just prior to the Reportable
Contingency Event was positive or equal to
zero, or

The Balancing Authority or Reserve Sharing Group
returned its ACE to:

Recovery Period:

BAL-002-0 Mapping to Proposed NERC Reliability Standard BAL-002-2
Comment
Proposed Standard BAL-002-2

A Balancing Authority or Reserve
Sharing Group shall fully restore
its Contingency Reserves within

This Requirement has been
moved into the BAL-002-2
“Contingency Event

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event
June 4, 2012

R6.

Standard BAL-002-0
NERC Board Approved
R5.2. The Reserve Sharing Group
reviews each member’s ACE in
response to the activation of
reserves. To be in compliance, a
member’s ACE (or its equivalent)
must meet the Disturbance
Recovery Criterion after the
schedule change(s) related to
reserve sharing have been fully
implemented, and within the
Disturbance Recovery Period.

12

A period not exceeding 90 minutes following the end of

Contingency Reserve Restoration Period:

BAL-002-2

4.4. Reporting and record keeping processes

4.3. The procedure for activating reserves

4.2. Allocation of reserves among members

4.1. The minimum reserve requirement for the group

R4. Each Reserve Sharing Group or Frequency Response
Sharing Group shall have a signed agreement among the
participating Balancing Authorities addressing each of
the following:

Requirement R4

BAL-012-0

Reserve Sharing Group need only demonstrate ACE
recovery of at least equal to its MSSC, less the sum
of the magnitudes of all Previous Balancing
Contingency Events that have not completed their
Contingency Reserve Restoration Periods.

BAL-002-0 Mapping to Proposed NERC Reliability Standard BAL-002-2
Comment
Proposed Standard BAL-002-2

Restoration Period” definition

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event
June 4, 2012

R6.2. The default Contingency
Reserve Restoration Period
is 90 minutes.

R6.1. The Contingency Reserve
Restoration Period begins at
the end of the Disturbance
Recovery Period.

Standard BAL-002-0
NERC Board Approved
the Contingency Reserve
Restoration Period for its
Interconnection.

following the start of the Balancing Contingency
Event.

13

the Contingency Event Recovery Period, during which
the amount of Contingency Reserve deployed to
recover from a Balancing Contingency Event is to be
restored. A period not exceeding 15 minutes

BAL-002-0 Mapping to Proposed NERC Reliability Standard BAL-002-2
Comment
Proposed Standard BAL-002-2

Standards Announcement

Project 2010-14.1 Phase 1 of Balancing Authority Reliability-based
Controls: Reserves
Formal Comment Period Open: June 4 – July 3, 2012
Now Available
Formal comment periods are open for the following four standards: BAL-001-1 - Real Power Balancing Control
Performance, BAL-002-2 - Contingency Reserve for Recovery from a Balancing Contingency Event, BAL-012-1 Operating Reserve Planning, and BAL-013-1 - Large Loss of Load Performance through 8 p.m. Tuesday, July 3,
2012.
Instructions for Commenting
Formal comment periods are open through 8 p.m. Eastern on Tuesday, July 3, 2012.
Please use following comment forms to submit comments:
Comment Form – BAL-001-1
Comment Form – BAL-002-2
Comment Form – BAL-012-1
Comment Form – BAL-013-1
Due to the length of the definitions and the formatting limitations of the electronic commenting software,
please refer to the Unofficial Comment Form in Word on the project page for redlines referenced in Question
Two for BAL-001-1 in the electronic comment form.
If you experience any difficulties in using the electronic forms, please contact Monica Benson at
[email protected]. An off-line, unofficial copy of each of the comment forms is posted on the project
page.
Next Steps
The drafting team will consider all comments and determine whether to make changes to the standards and
associated documents. After the standards and associated documents are revised, the drafting team will submit
its work for quality review prior to the next posting.
Background
The NERC Standards Committee approved the merger of Project 2007-05 Balancing Authority Controls and
Project 2007-18 Reliability-based Control as Project 2010-14 Balancing Authority Reliability-based Controls on
July 28, 2010. The NERC Standards Committee also approved the separation of Project 2010-14 Balancing
Authority Reliability-based Controls into two phases and moving Phase 1 (Project 2010-14.1 Balancing Authority
Reliability-based Controls – Reserves) into formal standards development on July 13, 2011. The Standard

Drafting Team has revised BAL-001-0.1a Real Power Balancing Control Performance and BAL-002-1 Disturbance
Control Performance. The Standard Drafting Team proposes to eliminate the CPS2 metric in the present BAL001-01a standard and replace it with a new Balancing Authority ACE limits metric. The Standard Drafting Team
has completely revised the current BAL-002-1 standard to eliminate the ambiguity and move requirements from
the “Additional Compliance Information” section into the requirements section. The Standard Drafting Team is
also proposing two new standards BAL-012-1 Operating Reserve Planning, and BAL-013-1 Large Loss of Load
Performance to address planning for Regulating, Contingency and Frequency Responsive Reserves and
responding to a Large Loss of Load event.
The four standards within Project 2010-14.1 are an important part of the ERO’s strategic goal to develop
technically sufficient standards with requirements that provide clear and unambiguous performance
expectations and reliability benefits.
Standards Development Process
The Standards Processes Manual contains all the procedures governing the standards development process.
The success of the NERC standards development process depends on stakeholder participation. We extend out
thanks to all those who participate.

For more information or assistance, please contact Monica Benson,
Standards Process 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

Announcement – Initial Posting of Phase 1 of Balancing Authority Reliability-based Controls: Reserves

2

Name (20 Responses)
Organization (20 Responses)
Group Name (13 Responses)
Lead Contact (13 Responses)
Question 1 (33 Responses)
Question 1 Comments (33 Responses)
Question 2 (27 Responses)
Question 2 Comments (33 Responses)
Question 3 (30 Responses)
Question 3 Comments (33 Responses)
Question 4 (26 Responses)
Question 4 Comments (33 Responses)
Question 5 (25 Responses)
Question 5 Comments (33 Responses)
Question 6 (0 Responses)
Question 6 Comments (33 Responses)
Question 7 (0 Responses)
Question 7 Comments (33 Responses)

Individual
Robert Blohm
Keen Resources Asia Ltd.
No
The definition of "Pre-Reportable Contingency Event ACE Value" is written in convoluted English. It
can be written simply as: "The value of ACE immediately prior to the earliest Reportable Contingency
Event that occurred after the last time all previous Reportable Contingency Events’ recovery periods
had expired."
Yes
Yes
Yes
Yes

Individual
Joe Tarantino
Sacramento Municipal Utility Disrtict
Yes
Yes
Yes
Yes
Yes

Individual
Brendan Kirby
Consult Kirby
No
The language in the definition of “Balancing Contingency Event” under C. a. i. and ii. appears to allow
deployment of contingency reserves in the case when a generator fails to come back from a
maintenance outage. Or contingency reserves could be deployed if a generator is forced off line early
in the day. If either of these generators was being counted on to provide energy during the upcoming
peak period the system operator might conclude that this will “leave the responsible entity unable to
maintain its ACE following the failure, unless it deploys Contingency Reserve.” My concern is that the
contingency reserves can be deployed before there is any ACE deviation (“…not an immediate cause
of an unexpected change to the responsible entity’s ACE…”). Since there is no ACE deviation there is
no DCS event start time and consequently no requirement to restore reserves. There is no
Contingency Event Recovery Period and no Contingency Reserve Restoration Period. Further, simply
declaring that a generator has unexpectedly become unavailable and the system operator feels the
system will be unable to maintain ACE without deploying contingency reserves now exempts the
system from DCS accountability indefinitely because any further contingency will be greater than the
Balancing Authority’s Most Severe Single Contingency. The language in the second bullet under R1
appears to grant this exemption because the first generator failure, which did not result in an ACE
deviation, never started the clock that would end the Contingency Reserve Restoration Period.
Yes
No
If the Balancing Contingency Event definition is not changed to eliminate the use of contingency
reserves prior to an actual event then that must be addressed here.
Yes

Individual
Anthony Jablonski
ReliabilityFirst
No
ReliabilityFirst offers the following comments for consideration related to the proposed defintions: 1.
Definition of Balancing Contingency Event a. RFC seeks further clarification on section C of the
definition of Balancing Contingency Event. Based on the language, RFC believes this section is already
covered in section A. The “Inability to start a unit…” and “Internal plant equipment problems that
force the generator to be ramped down or taken offline” seems to be very similar as a “unit tripping”
or a “Loss of generator Interconnection Facilities resulting in isolation of the generator from the Bulk
Electric System” which is covered in section A. RFC recommends removing section C. 2. Definition of
Reportable Contingency Event: a. RFC questions how the 80 percent value was determined. Is there
an associated technical justification for this value? If so, can the SDT explain?

Group
PacifiCorp

Sandra Shaffer
Yes
Yes
Yes
Yes

PacifiCorp is concerned about the deletion of the highlighted language from the Applicability section of
BAL-002-2. Without this language, it could be interpreted to mean that both Balancing Authorities and
Reserve Sharing Groups must comply with the standard. Under BAL-002-1, Balancing Authorities may
meet the requirements through participation in a Reserve Sharing Group. While this information is set
forth in the Additional Compliance Section 1.4, the Federal Energy Regulatory Commission has taken
the position that information set forth in the Additional Compliance Section is not part of the
requirements of the standard and thus, may not be used to interpret the standard. As a result,
PacifiCorp suggests including this explicitly in the Applicability or Requirements section of the
standard. PacifiCorp would also propose including the other language contained in the Additional
Compliance Section in the Requirements portion of the standard to ensure that it will be interpreted
as part of the standard. 4. Applicability 4.1 Balancing Authority 4.2 Reserve Sharing Group (Balancing
Authorities may meet the requirements of Standard 002 through participation in a Reserve Sharing
Group.)
Individual
Greg Travis
Idaho Power Company
Yes
Yes
Yes
Yes
Yes
None
No
Individual
Michael Falvo
Independent Electricity System Operator
No
1. The term Balancing Contingency Event, Category B: we suggest changing “non-interruptible
import” to “import” since a BA must be able to meet DCS requirement and recover ACE regardless of
the type of import that gets curtailed or interrupted. A sudden loss to an interruptible import has the
same resource deficiency impact on the importing BA. 2. The term Most Severe Single Contingency:
The wording “or the greatest loss of activated Direct Control Load Management used by the Balancing
Authority” gives the misconception that it is the loss of the load under the Direct Control Load
Management program. Such a loss will actual result in increasing available resource in the BA area,
which enhance the BA’s capability to meet firm system load and non-interruptible export obligation.
We suggest to revise the wording to “or the greatest loss of capability of Direct Control Load

Management used by the Balancing Authority…” 3. Contingency Event Recovery Period: We do not
agree with the proposed start time. The period should start when tie deviation exceeds the reporting
threshold. Operators do not normally start implementing remedies until the threshold level is
exceeded. It is not clear when the recovery period begins for Balancing Contingency Event Category
C, as it may not be an immediate cause of an unexpected change to ACE with the responsible entity’s
judgment also a factor. 4. Balancing Contingency Event: Category C requires clarification in order to
determine the magnitude of the contingency event. For example, if a 900 MW generating unit failed to
start that was to ramp to full output in 45 minutes and in the Entity’s judgment, contingency reserve
is required to restore ACE, what is the magnitude of the contingency? Categories A and B are straight
forward as they both relate to sudden losses, however it is unclear on how to determine magnitude
for reporting purposes.
Yes
No
1. The requirement states that the BA or RSG experiencing a Reportable Contingency Event shall
implement its Contingency Reserve Plan, which implies that it must be done. There could be
occurrences where a Reportable Contingency Event has occurred, where ACE is restored without the
need for activating contingency reserve. For example, pre-contingency ACE is positive and demand is
reducing just prior to event and following the event, ACE meets requirements. Must a BA or RSG
activate contingency reserve if not required? BAL-002-1 states that each BA or RSG shall activate
sufficient Contingency Reserve to comply with the DCS, which implies that it is activated as required.
Suggest revising to provide clarification.
Yes
Yes

There is no technical basis provided for the 500 MW reporting threshold, and its universal application
across all Interconnections is not explained in the standard or the background document.
Individual
Michael Goggin
American Wind Energy Association
No
It may be efficient and desirable from a reliability standpoint to use contingency reserves under some
circumstances to help accommodate the initial phase of extreme ramps in wind energy output, which
would not be allowed under the standard as currently drafted. Since extreme wind events would be
extremely rare (a few times per year) and short-lived (typically shorter than an hour or two in
duration), such events would be highly unlikely to coincide with other demands for contingency
reserves. For equity reasons it may also make sense to expand access to contingency reserves to
wind plants, since contingency reserves are maintained for all users of the power system, yet under
current rules wind plants use far fewer contingency reserves than other types of generation.
Yes
Yes
Yes
Yes

Group

Progress Energy
Jim Eckelkamp
No
Reportable Contingency Event should be changed to read “Any Balancing Contingency Event greater
than or equal to 80 percent of the Balancing Authority’s Most Severe Single Contingency.” The 500
MW amount in the proposed definition is not necessary and will not improve Reliability of the BES.
The basis or rationale for the 500 MW amount is not discussed in the background document. The
proposed Pre-Reportable Contingency Event ACE Value needs to provide a specific time frame for
calculating pre-event ACE instead of “immediately prior.”
No
This Standard should be combined with the proposed BAL-013 to cover all sudden ACE deviations
greater than a certain magnitude occurring in one minute of less, regardless of if the event is a loss of
generation, resources, or load.
No
The fourth bulleted item “Provided….” is not clearly worded in a manner that would allow for easy
understanding of what is required. It is not clear when the “clock” starts and ends for a series of
contingency events that exceeds the MSSC. PEC agrees with the concept that timely restoration of
ACE needs to take place, even when the event exceeds the MSSC, however the required time frames
must be clearly defined and understandable to System Operators and Resource Planners.
No
There is no background or rationale given for the 500 MW threshold required for a “Reportable
Contingency Event.”
Should “Reporting ACE” that is a newly defined proposed term be used in place of just “ACE” in order
to achieve consistency across this set of Standards proposed in this Operating Reserves project?
Individual
Thad Ness
American Electric Power
Yes
Yes
Yes
Yes
Yes

Group
Northeast Power Coordinating Council
Guy Zito
No
In order to address the proper treatment of slowly evolving generation losses, the second sentence of
the definition of Contingency Event Recovery Period should be revised to read: “…The start of the
Balancing Contingency Event is the point in time where the first change in MW is observed due to the
event that occurs within the first minute in which the change in MW output exceeds the size of the
applicable Reportable Contingency Event.” For the Reportable Contingency Event, the 500MW
reporting threshold would be a reduction in the DCS threshold for some Balancing Authorities. This

could present a double jeopardy situation with the NPCC spinning reserve requirement determination.
No
Requirement R1 has the proper concepts, but the bullets should be rewritten for clarity. Suggested
rewording: o The Balancing Authority or Reserve Sharing Group: o If its ACE was positive or equal to
zero just prior to the Reportable Contingency Event returned its ACE to zero less the sum of the
magnitudes of all subsequent Balancing Contingency Events that occur within the Contingency Event
Recovery Period, Or o If its ACE was negative just prior to the Reportable Contingency Event returned
its ACE to its Pre-Reportable Contingency Value less the sum of the magnitudes of all subsequent
Balancing Contingency Events that occur within the Contingency Event Recovery Period.

Violation Severity Levels have not been provided. The Standard does not address whether load
shedding should be used if necessary to be compliant.
Individual
John Tolo
Tucson Electric Power
No
While the definitions provide some clarity, there have been no reliability issues related to the
declaration of reportable events. Therefore leave the threshold at 80% of MSSC.
Yes
No
I agree with the 4th bullet, bullets 2 and 3 have verbage added that may be confusing. I prefer the
existing R4.1 language. Currently there is no requirement for an Contingency Reserve Plan. If this
Standard passes on its own, then that implies another compliance requirement for which there is no
guidance.
No
With some modifications to R1, this Measure is acceptable.
No
Overall, the document provides clarity. However, the purpose of BAL-002-2 should be to recover from
contingencies, not measure the success of a plan.
no
Individual
Kathleen Goodman
ISO New England Inc.
No

Although generally supportive of the modified Standard, we know of no known reliability concerns
with the existing 80% FCL threshold on DCS and, therefore, do not understand or support the
lowering to 500 MW. We would support, however, development of a Reliability Guideline, similar to
what is being done for System Operator Verbal Communications, to enable reporting of smaller
events (i.e. greater than 500 MW) to achieve more granular data and a larger sample set for potential
future use, if deemed necessary by analysis. We would also provide a comment for the SDT to
consider: although DCS compliance is important from a standpoint of ensuring adequate reserves are
available and able to respond to contingencies, we do not believe that extraordinary actions (i.e.
shedding of firm customer load) should be taken to comply with the DCS 15-minute recovery when
the frequency and transmission system are in a secure operating space. Somehow we would
appreciate it documented within BAL-002 that contingency recovery should not only place second
from frequency and transmission security, but would note that striving for compliance with the DCS
15-minute recovery in some instances may actually create more harm on the system from an
operating reliability perspective by having negative impact on limits or frequency.
No
Although generally supportive of the modified Standard, we know of no known reliability concerns
with the existing 80% FCL threshold on DCS and, therefore, do not understand or support the
lowering to 500 MW. We would support, however, development of a Reliability Guideline, similar to
what is being done for System Operator Verbal Communications, to enable reporting of smaller
events (i.e. greater than 500 MW) to achieve more granular data and a larger sample set for potential
future use, if deemed necessary by analysis. We would also provide a comment for the SDT to
consider: although DCS compliance is important from a standpoint of ensuring adequate reserves are
available and able to respond to contingencies, we do not believe that extraordinary actions (i.e.
shedding of firm customer load) should be taken to comply with the DCS 15-minute recovery when
the frequency and transmission system are in a secure operating space. Somehow we would
appreciate it documented within BAL-002 that contingency recovery should not only place second
from frequency and transmission security, but would note that striving for compliance with the DCS
15-minute recovery in some instances may actually create more harm on the system from an
operating reliability perspective by having negative impact on limits or frequency.
No
Although generally supportive of the modified Standard, we know of no known reliability concerns
with the existing 80% FCL threshold on DCS and, therefore, do not understand or support the
lowering to 500 MW. We would support, however, development of a Reliability Guideline, similar to
what is being done for System Operator Verbal Communications, to enable reporting of smaller
events (i.e. greater than 500 MW) to achieve more granular data and a larger sample set for potential
future use, if deemed necessary by analysis. We would also provide a comment for the SDT to
consider: although DCS compliance is important from a standpoint of ensuring adequate reserves are
available and able to respond to contingencies, we do not believe that extraordinary actions (i.e.
shedding of firm customer load) should be taken to comply with the DCS 15-minute recovery when
the frequency and transmission system are in a secure operating space. Somehow we would
appreciate it documented within BAL-002 that contingency recovery should not only place second
from frequency and transmission security, but would note that striving for compliance with the DCS
15-minute recovery in some instances may actually create more harm on the system from an
operating reliability perspective by having negative impact on limits or frequency.
No
Given the rampant need in the industry for Requests for Interpretations, Rapid Revisions, and CANs,
we believe that future Standards need to be written so that they can "stand alone" upon scrutiny.

Group
Arizona Public Service Company
Janet Smith, Regulatory Affairs Supervisor
Yes

Yes
Yes
Yes – This is a long and potentially complicated requirement. There will definitely need to be a further
explanation/examples included for clarification.
Yes
No
No - The current BAL-002-1 states that its purpose is to “to ensure the Balancing Authority is able to
utilize its Contingency Reserve to balance resources and demand and return Interconnection
frequency within defined limits following a Reportable Disturbance” while the draft states its purpose
is “to ensure the Balancing Authority or Reserve Sharing Group utilizes its Contingency Reserve to
balance resources and demand and return the Balancing Authority’s or Reserve Sharing Group’s Area
Control Error to defined values”. The background document does not discuss the reasoning for the
difference in purpose statements.
No conflicts
Utilities will start units earlier than required to ensure they are available when needed for reserve
purposes. Balancing Contingency Event definition “C” would seem to allow for waiting until the unit is
actually needed and then declare an event if the unit fails to start.
Group
Southern Company
Antonio Grayson
No
Southern Company does not agree with the 500MW specification in the definition of “Reportable
Contingency Event”. It is unclear what the basis for this value is. The background document did not
provide any technical basis for this value. Please explain why this value was chosen. Southern
suggest that each interconnection have a distinctive reporting level based on frequency impact and do
not agree with the 500MW value in the definition of ‘Reportable Contingency Event’. We propose that
the definition of ‘Reportable Contingency Event’ be changed to ‘Reportable Balancing Contingency
Event’. Southern recommends that the definition of ‘Balancing Contingency Event’ include Direct
Control Load Management and be removed from the definition of MSSC. Also, as it relates to the
definitions of ‘Balancing Contingency Event’ and ‘Most Severe Single Contingency’, it is unclear what
constitutes an event and is ultimately considered the MSSC. To avoid any misinterpretation by the
industry or compliance enforcement entities, the SDT needs to clarify what types of events should
considered a MSSC. Examples: • Would a tornado causing the trip of multiple units at a site that
exceeds the loss of the most severe single generating unit contingency be considered a credible
contingency? • Would common scrubber, common GSU, etc. type events be considered credible
contingencies in the identification of the MSSC? In general, Southern is concerned that credible but
unlikely events would be construed as an MSSC for an entity and suggest the SDT to create a
technical document with more clarification on this. We also suggest that “Sudden Loss” be clarified to
occur within a one (1) minute time frame. We suggest changing the verbiage of the first sentence of
‘Contingency Event Recovery Period’ to read ‘A period not exceeding 15 minutes following the start of
the reportable Balancing Contingency Event’. We further suggest changing the verbiage of the first
sentence of ‘Contingency Event Restoration Period’ to read, ‘A period not exceeding 15 minutes
following the start of the reportable Balancing Contingency Event’.
Yes
No
R1 should not require the implementation of the Contingency Reserve Plan. ACE recovery is the goal,
not the implementation of the plan.
No
The Measure for the proposed Requirement requires reporting for units >80% of the largest
contingency; however, the Measure does not address units >=500MW as stated in the definition of
‘Reportable Contingency Event’. Southern Company does not agree with the 500MW specification in

the definition of “Reportable Contingency Event”. It is unclear what the basis for this value is. The
background document did not provide any technical basis for this value. Please explain why this value
was chosen. Southern suggest that each interconnection have a distinctive reporting level based on
frequency impact and do not agree with the 500MW value in the definition of ‘Reportable Contingency
Event’.
No
The background document addresses carrying reserves to recover from the most severe single
contingency. There seems to be no rationale or explanation for reporting events less than 80% of the
MSSC. Please explain why the rationale for reporting events greater than 500 MW.

Individual
Chris Mattson
Tacoma Power
No
Tacoma Power generally agrees with the definitions as proposed. However, the use of the term
“Balancing Authority” should be clarified in the definitions of MSSC and Pre-Reportable Contingency
Event ACE Value. Tacoma Power suggests that the term be replaced with “Reserve Sharing Group or a
Balancing Authority not in a Reserve Sharing Group.” These definitions should only apply to a
Balancing Authority when the Balancing Authority is not a member of a Reserve Sharing Group.
No
Tacoma Power generally agrees with the purpose statement as proposed. However, the use of the
term “Balancing Authority” should be clarified. Tacoma Power suggests that the term be replaced with
“Reserve Sharing Group or a Balancing Authority not in a Reserve Sharing Group.” The purpose of this
standard should only apply to a Balancing Authority when the Balancing Authority is not a member of
a Reserve Sharing Group.
No
Tacoma Power generally agrees with the Requirement as proposed. However, the use of the term
“Balancing Authority” should be clarified. Tacoma Power suggests that the term be replaced with
“Reserve Sharing Group or a Balancing Authority not in a Reserve Sharing Group.” The Requirement
should only apply to a Balancing Authority when the Balancing Authority is not a member of a
Reserve Sharing Group.
No
Tacoma Power generally agrees with the Measure for the proposed Requirement as proposed.
However, the use of the term “Balancing Authority” should be clarified. Tacoma Power suggests that
the term be replaced with “Reserve Sharing Group or a Balancing Authority not in a Reserve Sharing
Group.” The Measure for the proposed Requirement should only apply to a Balancing Authority when
the Balancing Authority is not a member of a Reserve Sharing Group.
Yes
Tacoma Power does not have any concerns with the document at this time.
Tacoma Power is concerned how the proposed standard can be interpreted for application to
Balancing Authorities. The proposed standard should only apply to a Balancing Authority when the
Balancing Authority is not a member of a Reserve Sharing Group.
Tacoma Power appreciates the opportunity to comment on the proposed standard and thanks you for
your consideration of our comments.
Group
LG&E and KU Services
Brent Ingebrigtson
No
Balancing Contingency Event B. Sudden Loss of Non-Interruptible Import LG&E and KU Services
suggest striking the language “due to forced outage of transmission equipment.” A reliability entity
can cut a tag for reasons other than a forced outage of transmission equipment (equipment OLs,
contingency/stability/voltage criteria, etc.) – the sink BA experiencing the loss of the import may not

know the reason and thus not know if the loss meets the definition of a Balancing Contingency Event.
It is unclear whether “non-interruptible” means firm transmission or firm power. C. Unexpected
Failure of Generation to Maintain or Increase It’s wrong to assume that the failure of a generator to
start or increase will negatively impact ACE or BES reliability – the start may be for testing, an
early/preemptive/precautionary start or similar action that does not negatively impact ACE. Language
under “C. b.” is vague, overly broad, and is prone to interpretation or selective enforcement by CEAs.
LKE suggests “C” be deleted. This language could be added to “A” to cover situations where lack of
generator performance negatively impacts ACE. Most Severe Single Contingency (MSSC) NERC
currently does not have a definition for MSSC so this is the first attempt to draft such a definition. But
this does not need to be defined since Contingency is already a NERC Glossary term. Since
Contingency is already defined and the terms “single” and “most severe” are clear and unambiguous
in their meaning, it is unnecessary to define MSSC. A Balancing Contingency Event (BCE) is only
recognized after it occurs but the MSSC is a forward-looking/planned/forecasted/predicted value. It is
not possible for an entity to predict the largest BCE that could possibly occur. The MSSC definition as
drafted is too broad. The loss of Direct Control Load Management should be included in the definition
of Balancing Contingency Event and not thrown into any definition of MSSC (i.e. make loss of DCLM a
type of BCE). For non-interruptible export obligations – it is unclear how the source BA should know
that the sink BA carries CRs to cover the export. As written, it appears that if the sink BA carries CRs
then the export will not be considered as a potential MSSC for the source BA but it could be the MSSC
for the sink BA. Reportable Contingency Event The NERC Glossary currently defines a “Reportable
Disturbance” (vs. the proposed Reportable Contingency Event). It is unclear whether the definition of
Reportable Disturbance will be deleted. To be consistent, call it a “Reportable Balancing Contingency
Event”. There is no apparent reliability need to lower the reporting threshold below the current 80%
of MSSC. Applying a “hard” reporting threshold like 500MW for all BAs does not seem efficient or
realistic due to the wide range of BA sizes. If the SDT is aware of any reliability purpose for changing
the threshold, it should make that available to the industry. Such transparency by the SDT will benefit
discussions in building industry consensus. Contingency Event Recovery Period LG&E and KU Services
suggest “A period not exceeding 15 minutes following the start of the Reportable Balancing
Contingency Event. The start of the Reportable Balancing Contingency Event is the point in time
where the first change in ACE is observed due to the event.” Otherwise Contingency Event Recovery
Period is applicable to all BCEs which is inconsistent with the Purpose statement of the standard. Also,
it may be difficult to ascertain exactly “where the first change in MW is observed due to the event” –
the first MW change could occur several seconds or minutes prior to recognition of the occurrence of a
Reportable Contingency Event. Contingency Reserve Restoration Period LG&E and KU Services
suggest “A period not exceeding 90 minutes following the end of the Contingency Event Recovery
Period, during which the Amount of Contingency Reserve deployed to recover from a Reportable
Balancing Contingency Event is to be restored.” Otherwise Contingency Reserve Restoration Period is
applicable to all BCEs which is inconsistent with the Purpose statement of the standard. PreReportable Contingency Event ACE Value LG&E and KU Services suggest: The value of ACE
immediately prior to a Reportable Balancing Contingency Event when there are no previous
Reportable Balancing Contingency Events for which the Contingency Event Recovery Period is not yet
completed, or The value of ACE that the Balancing Authority or Reserve Sharing Group must attain to
fully meet its ACE recovery requirement with respect to the immediately previous Reportable
Balancing Contingency Event for which the Contingency Event Recovery Period is not yet completed.
No
R1 should not require the implementation of the CR plan – ACE recovery is the goal, not
implementation of the CR plan. Standards should be “results based”. Requirements should focus on
what is needed for reliability, not “how” it is achieved. Compliance with R1 should not be dependent
on correct implementation of a plan. “Previous” should not be capitalized.

The language used in the definitions and the language used in R1 is confusing. The definitions and
parts of R1 indicate the 15 minute ACE recovery and 90 minute CR recovery clocks are applicable to
all BCEs – not just the reportables. But R1 is clearly applicable only to Reportable CEs. Consistency is
needed between the terms and language used in the definitions and R1. What is the reliability

purpose for extending the data retention period out to current year plus 3 calendar years from the
currently required 1 year minimum? LG&E and KU Service suggests that the SDT provide clarification
on reporting requirements, and provide its reasoning for such reporting requirements
Individual
Ed Davis
Entergy Services
No
There is a concern with the definition regarding ‘Contingency Event Recovery Period’ and when the
15-minute clock starts if a unit is experiencing issues and has a drop in MW output but does not
actually trip offline until sometime later. The way the definition is proposed is that ‘The start of the
Balancing Contingency Event is the point in time where the FIRST change in MW is observed due to
the event’. In some instances, this may not be for some period before a unit actually trips offline
(possibly after the 15 minute window) or is able to recover from another issue. Also, the EMO/SPO
does not agree with the proposed definition of ‘Reportable Contingency Event’ as currently being
drafted, particularly ‘the LESSER amount of 80 percent of the Balancing Authority’s Most Severe
Single Contingency OR 500 MW’. We do not agree that any MW loss less than 80% of the MSSC
should be considered a Reportable Contingency Event.

Group
Bonneville Power Administration
Chris Higgins
No
The definition doesn’t contain the “Single” portion of MSSC. This describes any event (multiple
contingencies) of any size. BPA would like to see the definition expanded to include the “Single”
portion of MSSC.
Yes
No
BPA believes the first paragraph of R1 should be removed. The “shall implement its Contingency
Reserve plan” is covered in another requirement, which is referring to another potential standard.
What if an entity has a choice between implementing NERC’s plan, or meeting DCS? BPA appreciated
the addition of the last bullet.
No
BPA does not support the proposed Measure in the standard because BPA disagrees with the
requirement.
No
The last sentence of the Introduction states: The primary objective of BAL-002-2 is to measure the
success of implementing a Contingency Reserve plan. BPA believes the primary objective is to recover
from contingency events for the reliability of the system, not to ensure a plan is followed.

Group
SPP Standards Review Group
Robert Rhodes
No
Balancing Contingency Event - This definition is extremely complicated and contains numerous
intertwined components which make it difficult, at best, to ascertain compliance. Is there any way the

SDT could simplify or consolidate elements of this definition to make it more palatable? Further
explanation could be included in the background document. In Section C., what is the generation
expected to maintain or increase? Is it MW, MVAR, boiler pressure, etc.? Also in Section C.a.i., we
would suggest that the item read: i. inability to start a unit (for reasons other than lack of fuel) the
Responsible Entity planned to bring online at that time, or Reportable Contingency Event – We have
some concern over the addition of the 500 MW reporting criteria in this definition. Within SPP this
raises the risk level of the Reserve Sharing Group considerably. What was the basis for including this
criteria? Such an explanation was missing in the background document. Could the SDT please share
their thinking on this issue? Within SPP, we have an established criteria whereby contingencies of 600
MW or greater are reviewed for DCS compliance whereas our official DCS compliance reporting
criteria is approximately 1,000 MW. If such a requirement is needed and the SDT can share the
reasoning behind that requirement, we would propose to set the threshold at 600 MW.
Yes
No
We are unsure of exactly what the reporting requirements are for R1. In the existing BAL-002-1, it is
pretty clearly laid out, although spread out throughout the standard, what the BA or RSG must report
to demonstrate compliance. It’s contained in M1 and Section D.1.5. The existing BAL-002-1 also
offers two options for reporting compliance for an RSG – one from the RSG perspective and one from
the RSG participants taken individually. R1 implies that only the RSG as a group is to be reported. If
this is the case, the SDT could clarify this by including a term Reserve Sharing Group ACE, and its
definition, in the standard.
No
Please see our comment regarding reporting requirements in Question 3.
No
The document only contains a brief introductory paragraph, the requirement itself and another brief
paragraph consisting of only a few lines of background and rationale material. The document contains
no helpful information that provides any further clarity to the standard or the definitions used in the
standard. Additional information on the definitions is disparately needed as some of the definitions are
extremely complicated.
Not aware of conflicts.
No.
Group
ACES Power Marketing Standards Collaborators
Jason Marshall
No
The definition of Balancing Contingency event seems overly complicated and it is not clear it is even
needed. It appears to be an attempt to provide more precision over what constitutes a contingency
that may be subject to DCS. However, it does not address all situations and could actually result in
confusion over whether a particular situation is included as a result. For example, would a run back of
a generator over a two minute period constitute a Balancing Contingency Event? Traditionally, these
would be considered contingencies and subject to DCS if they meet the reportable event threshold.
However, because the definition is so precise and does not specifically mention run backs, we are left
confused over whether or not they are considered. The definition of Most Severe Single Contingency
(MSSC) is too complicated. We suggest it should be kept very simple. It should be no more
complicated than: “MSSC: The single most credible contingency that would result in the greatest
resource loss.” Even though there is a FERC directive to include Demand Side Management (DSM),
the definition does not specifically have to reference it as long as the generic “resource” is used. The
ultimate filing to FERC could simply explain that resource is intended to cover any type of resource
including DSM. This explanation could also be included in an application guidelines section along with
an explanation of the MSSC. We disagree with the definition of Reportable Contingency Event. First, it
is not clear why the current Reportable Event definition is not satisfactory and if it is not, it is not
clear why it is not being revised rather than creating a new term. The implementation plan does not
even consider retiring the Reportable Event definition. Second, no basis is provided for the 500 MW
threshold. Without a sound technical basis, it appears to be arbitrary. This is particularly troubling

considering that a BA or RSG can reduce the 80 percent threshold per section 1.4 of the standard. We
disagree with the definition of Contingency Event Recovery Period. It states that the period starts at
the point in time where the first change in MW is observed. For a generation runback over a period of
a few minutes, this is problematic and significantly shortens the time period to recover from the
contingency. It should start immediately after the final MWs of the contingency are lost. The definition
of Contingency Reserve Restoration Period is not needed and provides no additional clarity. It is used
only once in the standard in the second bullet under Requirement R1. The bullet would be clearer if it
directly stated that for any contingencies with an aggregate total that exceeds the MSSC that occur
within 90 minutes of the first contingency, the BA or RSG only has to recover for the loss of the
MSSC. The bullet correctly assumes that the BA or RSG will try to recover its contingency reserve in
less than 90 minutes. However, it is not necessary to refer to the Contingency Reserve Restoration
Period to cover this shorter period. The BA will either take the full 90 minutes to recover its
contingency reserve or the BA will recover the contingency reserve in less than 90 minutes. If a
contingency occurs before contingency reserve is fully recovered, the BA may have to use its
emergency procedures which are required in the EOP standards. If the BA has recovered the full
amount of its contingency reserve before the next contingency, it will be able to recover ACE. Thus,
reliability is preserved either way and the requirement is simpler.
Yes
No
We disagree with the implied requirement to have a contingency reserve plan. No such plan was
required in the existing standard and no justification has been provided for its need. There are
enough resource contingencies that actual demonstration of implementation of contingency reserve
should be sufficient.
No
It seems the only way to verify that ACE was recovered is to have ACE data available. Thus, we would
expect to see ACE in the measurement.
No
There is essentially a single paragraph of explanation in the background document. The rest is either
the requirement or an introduction. Significantly more background needs to be provided to explain
such dramatic changes to this standard. For example, why does the document imply a requirement to
have contingency reserve plan? No such requirement existed in the past. The existing standard was
fairly clear. Only a few refinements were necessary to the existing standard to address outstanding
issues.
In general, we do not understand the wholesale rewrite of this standard and the indirect and implicit
requirement to have a contingency reserve plan. We further do not understand why some of the
requirements were modified and moved to BAL-012-1 and BAL-013-1. One key issue really needed to
be addressed in this standard regarding clarifying within the requirement that a BA or RSG could not
be held in violation of the standard for a contingency that exceeds the MSSC. We disagree with the
data retention requirements of up to four years. First, it raises the bar without justification from the
current standard which only requires one year. Second, they are not consistent with NERC Rules of
Procedure. Section 3.1.4.2 of Appendix 4C – Compliance Monitoring and Enforcement Program states
that the compliance audit will cover the period from the day after the last compliance audit to the end
date of the current compliance audit. The “current year, plus three calendar years” exceeds the
compliance audit period of three years for the BA. Third, NERC already requires quarterly data reports
for DCS and will likely continue to require similar reports even with this new standard. Thus, NERC
can retain these reports for the four years if they need them. The implementation plan proposes to
retire both BAL-002-0 and BAL-002-1. BAL-002-0 has already been retired on March 31, 2012.
Individual
Don Jones
Texas Reliability Entity
No
The MSSC should not be limited to the greatest loss of generation output; it may also be due to the
loss of an import tie line. Even with the definition of “Balancing Contingency Event” including sudden

loss of non-interruptible import, the inclusion of “of generation output” phrase in the MSSC definition
could be misinterpreted. Suggest referencing Subsection A, B, or C of the Balancing Contingency
Event definition. Should there be any mention of Reserve Sharing Group obligations in the MSSC and
Reportable Contingency Event definitions (implied in Requirement 1 but not explicit in the
definitions)? Should the “Contingency Event Recovery Period” and “Contingency Reserve Restoration
Period” apply to all Balancing Contingency Events or only to Reportable Contingency Events, in order
to be consistent with Requirement R1? There is an existing definition for “Contingency Reserve” which
may need to be modified (refers to DCS standard and RRO). There is an existing definition for
“Disturbance Control Standard” which may need to be modified or deleted. There are existing
definitions for “Operating Reserve-Spinning” and ”Operating Reserve-Supplemental” which may need
to be modified (refer to “contingency event” and “Disturbance Recovery Period”).
No
The purpose statement does not match the title or the intent of the Standard. Need to ensure
consistency between the use of “Reportable Contingency Event” and “Balancing Contingency Event.”
Yes
We agree with the intent of last bulleted paragraph of R1 to require a BA or RSG to carry enough
contingency reserves for its MSSC, however the wording is confusing.
Yes

There should also be a requirement for compliance with the Contingency Reserve Restoration Period.
None is explicitly stated. R1 appears to only cover the Contingency Event Recovery Period as the
BA/RSG implements its Contingency Reserve plan.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
No
South Carolina Electric and Gas supports the comments submitted by the SERC OC Standards Review
Group
Yes
No
South Carolina Electric and Gas supports the comments submitted by the SERC OC Standards Review
Group
Yes
No
No
South Carolina Electric and Gas supports the comments submitted by the SERC OC Standards Review
Group
Individual
Karen Webb
City of Tallahassee
No
1. The City of Tallahassee (TAL) disagrees with the definition for Reportable Contingency Event, as it
does not provide the latitude to modify the minimum threshold as is discussed in section D.1.4.,
Additional Compliance Information, which states a BA or RSG can reduce the 80% threshold. 2. TAL
seeks clarification on the end-time for the Contingency Event Recovery Period. Without a defined endtime, entities would presumably define the end-time individually, including up to the maximum 15
minute period to restore ACE to the Pre-Contingency Event ACE Value. 3. TAL disagrees with the

proposed definition of the Most Severe Single Contingency, due to the inclusion of the loss of load
scenario. TAL believes loss of load can be measured in the proposed BAL-001-1, R2 30-minute
criterion.
Yes
Yes
Yes
No
TAL seeks additional information or examples in the background document to understand what events
require evidence of what level of recovery when combined with the Disturbance Recovery Periods.
1. Data Retention: TAL suggests a clarification to the requirement language that data retention is the
longer of either (a) the data retention period defined in the standard or (b) the period since the last
audit. As the proposed language reads, the need to retain evidence since the previous audit (if longer
than the defined retention period) is addressed in a separate area from the defined retention period.
2. Additional Compliance Information: This section states that a BA or RSG may optionally reduce the
80% threshold, but does not address reduction of the 500MW threshold. TAL is unclear as to whether
this was an intentional omission or if there is justification to only having the minimum threshold of
500MW.
Group
Associated Electric Cooperative, Inc., JRO00088
David Dockery
No
Reportable Contingency Event definition, and others as noted below: Remove: “or 500 MW” then
realign all other definitions accordingly, to remove loss of load contingency references Rationale: AECI
was encouraged to see that our industry cited a load-loss value other than the too-often cited 300
MW “tell DOE, so they won’t get caught flat-footed before our President or Congress?”, but we were
equally disappointed to discover there was no technical reliability-related justification for the 500 MW
value drafted within the supporting “BAL-002-2_Background_Document_Clean_20120601” document.
Because this 500 MW threshold is not technically supported and it stands in confusing conflict with the
300 MW DOE reporting threshold, it should be removed. (SEE AECI rationale posted with BAL-013-1
Question 1, regarding Large Loss of Load Event definition, pertaining to a PNNL technical study of the
Western Interconnection system.)
Yes
No
BAL-002-2 R1 changes: Remove: “so that the Balancing Authority or…”, ie remove everything that
follows within this requirement’s wording. Rationale: While Contingency Reserve plans are designed to
accomplish the bulleted items within this Requirement 1, there is no guarantee of their success in
every possible circumstance. Having these extra words assuring each plan’s achievement of other
requirements, only serves to expose the industry to double-jeopardy where a plan failed to cover
unimagined circumstances.
Yes
Wisely worded.
No
The SDT failed to technically justify their 500 MW load-related threshold.
No
Since the SDT changed data-retention from 1 to 3 years, the background document should provide
insight into that change. If the change is for audit-period, then those could become longer and so a
wording change should provide the necessary flexibility to cover that possibility.
Group

ISOs Standards Review Committee
Terry Bilke
No
1) The term Balancing Contingency Event is overly complex and pulls in things never intended in DCS
(failure of a generator to start or move). The only problem with today’s definition is that due to
differences between beta and Bias Setting, ACE magnitude does not equate to contingency size. 2)
The term Most Severe Single Contingency (MSSC) is now complicated in that it is nested with the
Contingency Event term. There is no need to change the existing definition. 3) We disagree with the
definition of Contingency Event Recovery Period. The period should start when tie deviation exceeds
the reporting threshold. Operators aren’t psychic and don’t know if a runback or other partial event
will turn into a reportable event. 4) The term Balancing Contingency Event, Category B: we suggest
changing “non-interruptible import” to “import” since a BA must be able to meet DCS requirement
and recover ACE regardless of the type of import that gets curtailed or interrupted. A sudden loss to
an interruptible import has the same resource deficiency impact on the importing BA. 5) The term
Most Severe Single Contingency: The wording “or the greatest loss of activated Direct Control Load
Management used by the Balancing Authority” gives the misconception that it is the loss of the load
under the Direct Control Load Management program. Such a loss will actual result in increasing
available resource in the BA area, which enhance the BA’s capability to meet firm system load and
non-interruptible export obligation. We suggest to revise the wording to “or the greatest loss of
capability of Direct Control Load Management used by the Balancing Authority…”
No
1) If the proposed BAL-001 BAAL requirement is approved, there is no need for BAL-002. 2) It should
be noted that BAs do not always use their Contingency Reserve service to respond to events. The
purpose would be better stated if it stated “To ensure the Balancing Authority or Reserve Sharing
Group balance resources and demand to be within defined values (subject to applicable limits)
following a Reportable Contingency Event..”
No
1) The requirement is fine when looking at BAL-002 in isolation. If the proposed BAL-001 BAAL
requirement is approved, there is no need for BAL-002. 2) While avoiding defining what constitutes a
contingency reserve policy, the drafting team has created a second issue as exactly what constitutes
a Contingency Reserve Plan? Since it is not defined the Industry is at risk to subjective evaluations of
any developed plan. 3) The compliance section of the standard should provide guidance on evaluating
fixed RSGs and dynamically allocated RSGs.
Yes
Yes

1) The 500 MW reporting threshold appears arbitrary, particularly when you’re using the same size for
all Interconnections. 2) Ultimately, if the BAL-001 BAAL requirement were approved, BAL-002 is a
redundant standard and should be retired. While the FERC made directives on BAL-002, BAAL is an
equally effective alternative standard that is easier to administer and does not need all the specially
proposed definitions.
Group
MISO Standards Collaborators
Marie Knox
No
• The term Balancing Contingency Event is overly complex, overly broad, and ambiguous. MISO notes
that, as written, the proposed term would require reporting for Bulk Electric System (BES) issues
never intended to be tracked as reportable events, i.e., failure of a generator to start or move.
Further, MISO notes that the currently used term Disturbance and its definition could easily be
modified to address the fact that ACE magnitude is not easily correlated to contingency size. MISO
also notes that, as Balancing Contingency Event is replacing Disturbance and Reportable Contingency
Event is replacing Reportable Disturbance, the introduction of these terms could result in

inconsistencies and ambiguities with Registered Entities’ obligations under other Reliability Standards
where these terms are utilized, e.g., BAL-003, EOP-004, EOP-005, EOP-006, IRO-005, etc. • The
determination of a Balancing Authority’s Most Severe Single Contingency (MSSC) is now complicated
by the nesting of the term Balancing Contingency Event. The nesting of the Balancing Contingency
Event into the definition and determination of a Balancing Authority’s MSSC limits a Balancing
Authority’s ability to utilize its Subject Matter Expertise and Engineering Judgment to determine its
MSSC. This appears unnecessary and would likely not result in any benefit to the reliability of the Bulk
Electric System as Balancing Authorities should be free to utilize its Subject Matter Expertise and
Engineering Judgment to determine its MSSC. The 500 MW reporting threshold appears arbitrary
considering that each Interconnection has different and variable characteristics that determine the
threshold of impact at which a Disturbance would be sufficient to necessitate reporting. Furthermore,
for large BAs or organized markets, this requirement doesn’t add any reliability enhancement or
benefit. Specifically, MISO calculates a set of Security Constrained Economic Dispatch (SCED)
generator setpoints every 5 minutes. If a 500 - 600 MW generator trips, MISO can, under most
circumstances, simply calculate and distribute a new set of generator setpoints. This system allows
the entire fleet of generation resources within the MISO BA to respond to generation losses and
events using normal operating procedures, replacing the lost generation within 5 - 10 minutes from
the time of the initial loss without requiring the initiation of emergency or abnormal operating
procedures or processes. Further, the MISO BA is able to respond to such generation losses while
retaining its ability to respond to major disturbances using its contingency reserves, i.e., the use of
the SCED system will, under most circumstances, preempt the need to tap into contingency reserves.
Accordingly, to treat these relatively small generation losses as Disturbance Control Standard (DCS)
events requiring the deployment of contingency reserves may actually pose additional risk to the BES
as contingency reserves would be deployed more often and unnecessarily. Further, such treatment
would also require the use of abnormal or emergency operating procedures rather than utilizing the
normal dispatch functions available to many system operators. Finally, MISO respectfully suggests
that the administrative efforts associated with the DCS reporting required could require large BAs or
organized markets to hire additional personnel simply to track these relatively small losses with no
attendant or associated benefit to the reliability of the BES.
No
MISO reiterates that, if the proposed BAL-001 BAAL requirement is approved, there is no need for
BAL-002. IF the BARC SDT disagrees, MISO proposes that the purpose should be revised to remove
the new term, Reportable Contingency Event.
No
MISO reiterates that, if the proposed BAL-001 BAAL requirement is approved, there is no need for
BAL-002. IF the BARC SDT disagrees, MISO proposes that R1 should be revised to remove the new
terms upon which MISO provided comment above, specifically Balancing Contingency Event,
Reportable Contingency Event, MSSC, Contingency Event Recovery Period, and Pre-Reportable
Contingency Event ACE Value.
Yes
Yes
MISO notes the use of cross-references and similar terms among and between Reliability Standards.
Accordingly, terms and concepts previously utilized in BAL-002-1 that have been replaced, modified,
or re-defined in BAL-002-2 may impact other Reliability Standards such as BAL-003, EOP-004, EOP005, EOP-006, IRO-005, etc. MISO notes that the use of cross-references and similar terms should be
evaluated to ensure consistency amongst the Reliability Standards and requirements. In particular,
where terms and requirements have been redefined, modified, or replaced in BAL-002-2, a crossreferenced or closely related standard or requirement could be impacted by the modification to BAL002-2. For example, EOP-004 governs Disturbance Reporting. The term Disturbance was once utilized
in BAL-002-2 and is now replaced with Balancing Contingency Event. Do these reliability standards
correlate? Should they? Hence, MISO notes to the BARC SDT that the creation of a new glossary
definition could result in ambiguity regarding required performance outcomes and obligations where a
previously defined term had been used and is maintained in cross-referenced or closely related
standards. For example, several Reliability Standards refer to and use Disturbance. It is unclear

whether this performance obligation remains tied only to events meeting the definition of a
Disturbance or whether they should now also apply to a Balancing Contingency Event. MISO
respectfully suggests that the BARC SDT perform a comprehensive review of BAL-002-2’s impact on
cross-referenced or closely related Reliability Standards prior to implementation.
Individual
Nicholas L. Hall
Constellation Energy Control and Dispatch, LLC
No
The term “Sudden Loss” has no time-reference, which creates confusion and potentially broad
interpretation when discussing Non-Interruptible Imports. Would a “Sudden Loss” of a schedule be
one that is curtailed 10 minutes ahead of its scheduled start, five minutes from the current time, or
instantaneously? Without a defined measurement for “Sudden Loss,” Balancing Authorities are subject
to a recovery standard which cannot be known ahead of time, creating an unreasonable burden for
recovery. Part c of the definition for a Sudden Loss of Generation needs further clarification on when
normal, recurring operating characteristics of a unit do not constitute sudden or unanticipated losses,
and whether they are not for consideration under this definition. The phrase “may not be subject”
creates significant uncertainty for determining when, and if, a loss of generation that is the result of
the normal, recurring characteristics of a unit would be considered under the definition, and therefore
held to recovery under the requirements contained in this standard. The definition for Unexpected
Failure of Generation to Maintain or Increase brings significant uncertainty to the process of
Contingency Event Recovery, as it fails to clarify the timeframe in which a failure of a unit to start
would impact a responsible entity such that it is unable to maintain its ACE. If, for example, a unit
slated for startup several hours in the future fails to start, well ahead of the timeframe in which it
would be needed for maintaining ACE, does that constitute a Reportable Event under this definition? If
so, does the event timing (i.e. 15 minute recovery period) begin with the discovery of the unit’s
inability to startup, or does it begin when the lack of that unit impacts the entities ACE equal to or
greater than 80% of its MSSC? Also, the reference to the inability to maintain ACE following failure
does not provide any boundaries, indicating that an inability to maintain ACE at zero could result in
the consideration of a failed startup as a balancing contingency event. The definition of MSSC seems
to exclude consideration of non-interruptible imports, which are clearly considered in other portions of
the standard. If loss of firm imports can be counted as Balancing Contingency Event in certain
circumstances, what would this imply for Load Only Balancing Authorities with no internal generation?
Since they cannot experience a loss of generation, how would the MSSC determination be applied to
determine if a Balancing Contingency Event qualifies as a Reportable Contingency Event? The
Contingency Event Recovery Period needs to include clarification on the “Start of the Balancing
Contingency Event,” particularly for instances in which the event is triggered either by interruption of
a firm schedule, or by an Unexpected Failure of Generation to Maintain or Increase that does not have
immediate or unexpected impact on an entity’s ACE. Given that both of the events mentioned in this
comment can play out over significant time periods (ramp time of a curtailment may be well into the
future, and impact of a failed start may not be seen in actual ACE for a similarly lengthy period of
time), would the start of the 15 minute recovery period be triggered from the actual event, or the
point at which it impacted the entity’s ACE by the lesser of 80% of MSSC or 500 MW? Similar
concerns on timing, as indicated above, exist for Contingency Reserve Restoration Period and PreReportable Contingency Event ACE Value. Both of these measures rely on a clear understanding of
the start of the event, and the definitions as written are vague in certain instances, as mentioned.
Also, clarity needs to be provided on what is meant by “ACE immediately prior,” in general. Does this
intend that the individual scan of ACE immediately preceding the start of the event be used, or the
clock minute average ACE prior? This has been an ongoing source of vagary in DCS standards, and
warrants clarification.
No
Given that the standard proposes the inclusion of events with the expectation of future impact to ACE,
not actual current impact, this purpose statement seems incomplete and misleading.
No
The precedent of exclusion of simultaneous events that exceed the MSSC has long acknowledged that
industry planning for N-1 contingencies is adequate and reasonable. The extension of compliance

obligations under this standard to events in excess of MSSC represents an unreasonable burden.
While we acknowledge that there is also a precedent of compliance burden to carry reserves sufficient
to replace MSSC, the specific extension of compliance obligation to recover within 15 minutes from
such events does not allow for the understanding that unforeseen and extreme circumstances can
impact an entity’s ability to recover even to within its MSSC. As a simple example, take a complete
failure of the BES into consideration, and it is clear that an obligation to recover MSSC for a loss in
excess can represent an unreasonable burden.
Yes
No
As indicated in comments related to definitions, the standard as drafted inserts significant uncertainty
as to evaluation and timing of Balancing Contingency Events.

Individual
Patricia Robertson
BC Hydro
No
1.Balancing Contingency Event: a.Point A.c. is not clear and can be subject to interpretation; b. The
change to ACE is not required to be “immediate” but point C.b. implies that it should be in all cases
except C.b.; 2. MSSC: The “Single” portion of this term is not clearly defined here. The definition
implies this is the “Most Severe Balancing Contingency Event” which can be any event whether it’s
cause by the loss of a single element or multiple elements simultaneously? 3.Reportable Contingency
Event: a.This is defined only for Balancing Authority, not for Reserve Sharing Group; b.Why 500 MW
for all Interconnections which are of different sizes? Is there a technical basis for this amount?
Yes
No
a. This is a 2-in-1 Requirement. The implementation of the CR plan should not be included here as it
is referred to another standard; b.The “sum of the magnitudes” is not clearly defined. Is it measured
by the change in ACE or by the MW loss? c.BCH appreciates the clarification provided in the last bullet
(MSSC).
No
BCH does not agree with the Requirement R1 as written and therefore does not agree with the
Measure.
No
The Introduction of the Background Document states: The primary objective of BAL-002-2 is to
measure the success of implementing a Contingency Reserve plan. BC Hydro believes the primary
objective is to ensure the deployment of sufficient Contingency Reserve to recover from Generation
loss events.
BC Hydro is not aware of any conflicts.
The unique situation where the output of a Jointly Owned Unit can be divided among multiple
Balancing Authorities such that the ACE change per individual BA may not be significant but the
impact of the loss of the unit may be significant to the BES should be recognized and addressed in
this standard. Currently, there is no requirement for each BA to recover its ACE in such situation.
Individual
Jay Campbell
NV Energy
Yes
Yes

Yes
Yes
Yes
The background document mainly re-states the standard and adds little to understanding.
No.
No.
Individual
Laura Lee
Duke Energy
No
Duke Energy does not agree with including “or 500 MW” within the definition of “Reportable
Contingency Event”. The impact of that amount of loss on the Eastern Interconnection frequency is
negligible and not a reliability issue. The definition of “Balancing Contingency Event” is too broad and
long. It is stated as any single event described in Subsections A, B, or C below, or any series of such
otherwise single events, with each separated from the next by less than one minute. Using the phrase
“or any series of such otherwise single events” leaves too much room for interpretation as to what is
applicable and what is not. For many of the circumstances described, there may not be a clear
threshold at times where the operator would recognize that the 15-minute clock has been triggered
similar to a traditional unit loss. Upon implementation of the Balancing Authority ACE Limit (“BAAL”),
the Interconnections will be operating to a real-time Standard designed to support the reliability
operation of the Interconnection in consideration of the Interconnection frequency, which will catch all
of the circumstances described if the resulting imbalance causes the Balancing Authority to exceed its
BAAL. Duke Energy believes that the DCS should be focused upon a specific set of contingencies,
similar to today, that clearly define for the operator when the measure is applicable. Please see other
comments provided under Question 7. SDT may consider two separate definitions for “Pre-Reportable
Contingency Event ACE Value” to avoid confusion. Having two definitions for one term creates
ambiguity. The SDT could consider having a separate definition for Balancing Contingency Event and
for each event. For example, “Sudden Loss of Generation” could state something like: A balancing
contingency event characterized by unit tripping, loss of generator interconnection Facilities… etc.
No
As it is possible that restoring ACE to a pre-contingency state may not require implementation of
Contingency Reserves, Duke Energy would suggest striking “utilizes its Contingency Reserves”, as the
standard should not dictate what resources are utilized by the Balancing Authority to be compliant.
Yes

It could be interpreted from the language in R6 of EOP-002-3, that a Balancing Authority is
considered in an emergency condition and should be implementing its emergency plan if it is not
capable of complying at any time to the DCS measure. In Duke Energy’s opinion, the inability of
Balancing Authority to meet the 15-minute DCS compliance threshold does not in itself represent a
reliability issue. Under what circumstances, if any, should the Balancing Authority shed firm load as a
last resort to ensure that it remains compliant to the Disturbance Control Standard? We would
appreciate the drafting team’s perspective on this point.
Upon implementation of the Balancing Authority ACE Limit (“BAAL”), the Interconnections will be
operating to a real-time Standard designed to support reliable operation and maintain Interconnection
frequency within predefined limits. The merit in also having DCS in place is that it will continue to
reinforce the discipline and situational awareness provided by having a Standard focused upon the
Balancing Authority with the contingent loss of a resource (based on a clear and well-established
criteria) being the “first responder” to that event while other Balancing Authorities at that time may
be assessing their own impact on Interconnection frequency under the BAAL. However, Duke Energy
is concerned with some of the revisions proposed in BAL-002-2. The clear and well-established criteria

of what triggers the DCS event has been blurred in the proposed revisions which leave far too much
up to the interpretation of after-the-fact compliance scrutiny. The criteria for what applies as a DCS
event must be clear – our operators have to have unquestionable guidance on this matter. BAAL will
catch all load and generation nuances on the system affecting operation as reflected in the ACE; in
our opinion, the criteria for DCS can remain focused on what’s needed to test the Balancing
Authority’s capability to respond to the loss of a resource – setting a reporting threshold at 80% or
greater of the MSSC in most cases has worked well for that purpose and Duke Energy would support
maintaining that criteria. Duke Energy is also concerned that the current treatment of DCS noncompliance appears to be driving some Balancing Authorities to consider actions up to and including
the shedding of firm load in order to be compliant. Is it the intent of the standard drafting team that
the Balancing Authority take all action, up to and including the shedding of firm load, in order to
never exceed the 15-minute DCS compliance limit? According to the the background document, R1 “is
intended to eliminate the ambiguities and questions associated with the existing standard. In addition
it allows BAs and RSGs to have [a] clear way to show compliance and support the Interconnections to
full extent of MSSC” but there is no explanation as to what the ambiguities are in the background
document or in the mapping document. There is a typo: “a” is missing in sentence above from
background document. Also, according to the Background Information for Quality Reviews, the
applicability section of the standard should indentify all of the functional entities assigned
responsibility for one or more requirements in the standard. However, according the functional model
the Reserve Sharing Group is not a functional entity. The glossary defines it as, “a group whose
members consist of two or more Balancing Authorities that collectively maintain, allocate, and supply
operating reserves required for each Balancing Authority’s use in recovering from contingencies within
the group...”If the Functional Model is followed strictly, the Reserve Sharing Group should not be in
the applicability section. There are no VRFs, Time Horizons, or VSLs for R1 in the standard and no
explanation as to why they are missing. The Additional Compliance Information section in the
standard, does not match up with the language in the Mapping Document. The standard has a chart
for four Requirements but there is only one requirement (R1) in the standard. Also the mapping
document indicates that the standard should have two requirements (R1 and R2). In the Compliance
Enforcement Authority Section the language does not mirror the default language Background
Information for Quality Reviews.
Individual
Alice Ireland
Xcel Energy
No
There are six terms defined here although the first term is not in bold. Xcel Energy assumes that the
six definitions presented above are part of the drafting team’s effort and is commenting on all six. The
definitions and requirement needs clarity as to which entity, the BA or RSG, is required to do
something. In the definition of MSSC, it states the BA but the Requirement states it is the BA or RSG.
If the MSSC is defined only for the BA, what is the MSSC for a RSG and what is a Balancing
Contingency Event for the RSG since by definition it has not MSSC? Xcel Energy recommends that the
definition for MSSC be expanded to address the RSG MSSC. Xcel Energy feels that several of these
definitions need further clarification, especially Reportable Contingency Event, Contingency Event
Recovery Period, Contingency Reserve Restoration Period, Balancing Contingency Event and PreReportable Contingency Event ACE Value. More detail follows. In the definition of Contingency
Reserve Restoration Period there is an error. An entity need only recover to the level of its MSSC at
that time, not recover the amount used. As an example, an entity has two units, its MSSC of 1,000
MWs and an 800 MW unit. During an event where the 1,000 MW unit is lost, the BA/RSG would have
to restore 1,000 MWs of reserve under the proposed definition even though its MSSC at this point is
only 800 MWS. The drafting team must address this discrepancy. Balancing Contingency Event It is
unclear whether the drafting team believes that this definition would prohibit the activation of
contingency reserves due to the unexpected loss of wind generation. The wording of the definition
“Balancing Contingency Event” could be interpreted to prohibit the activation of contingency reserves
due to the unexpected loss or an unexpected increase of the wind driving wind generators. With the
increased levels of wind generation seen in the industry today, it is unreasonable to prohibit activation
of contingency reserves for what at times may constitute over 50 percent of a Balancing Authority’s
generation resources serving its loads. The drafting team must either clarify that activations may be
for any resource or justify a position to the contrary. Additionally, the drafting team must justify why

there is a limit on activations for the loss of an import only in the event that the transmission system
experiences a forced outage. It has been Xcel Energy’s experience that the underlying cause of most
curtailments of transactions is unknown to the sink Balancing Authority until after the fact if the
curtailment is initiated by another entity. It also appears under this definition that the drafting team is
using a defined term “Non-Interruptible Import” which is not found in the current version of the NERC
Glossary. If the drafting team continues with this unsupported position, it must at least define what it
means by “Non-Interruptible Import” since under the standards, a BA or TOP can take action to
address a reliability problem, which can include curtailing any schedule for any reason, not just the
forced outage of a transmission system element. As currently drafted, it is unclear when a receiving
BA can or cannot activate reserves. Finally, under this definition, it would appear that the drafting
team is intending to limit the activation of contingency reserves only for the loss of resources
considered “firm” without defining what is or is not “firm”. As an example, if a PSE associated with a
Balancing Authority is buying the output of a 600 MW generator facility located in a different BA under
WSPP Schedule B (Unit Commitment) and that interchange transaction is cut, is that a Balancing
Contingency Event? As currently structured, only the loss of some resources would be events under
this standard. That would appear to leave a very large hole that could be exploited by industry
participants if the structure is not significantly improved. The drafting team must provide support for
the concept that only ”firm” resources can be supported by contingency reserves since the loss of any
resource can cause an entity’s ACE to change unexpectedly. Reportable Contingency Event The term
Reportable Contingency Event should be limited to an entity’s Most Severe Single Contingency. The
recommended definition would be “Any Balancing Contingency Event between the lesser amount of 80
percent of the Balancing Authority’s Most Severe Single Contingency or 500 MW and the Balancing
Authority’s Most Severe Single Contingency. An Event greater than the Balancing Authority’s Most
Severe Single Contingency is not a Reportable Contingency Event.” This definition would provide
clarity on the size of event that is intended to be addressed by the standard and will allow for
reasonable planning on the part of industry participants for issues considered part of normal
operations of a Balancing Authority. Additionally, the drafting team needs to further justify the use of
500 MW loss or try to set this up in relation to the size of the BA/RSG. The term Most Severe Single
Contingency is not linked to a single point of failure/element. This needs to be addressed. As written,
it could be argued that the loss of two units within a short time period is by definition the MSSC,
rather than a double contingency. It is also not clear why the drafting team has included the loss of
Direct Load Control Management in the definition. The drafting team needs to provide justification for
including only this portion of load side resources and excluding others such as Demand Response,
Demand Side Management, Interruptible Load, include all forms of loss of control of any activated or
preferably remove this concept from the definition.
No
The language of the requirement states that the BA/RSG must implement its plan. However,
implementation of a Contingency Reserve plan does not mean that an entity will meet the
performance requirement to restore ACE to any level. As currently worded, it is unclear if an entity
were to meet the performance requirement by utilizing a resource not shown in the plan has met the
requirement or not. If there is a requirement to implement a plan, it should be separated from the
requirement to perform any other action as well as address the issue of use of a resource not included
in the plan. It is unclear why ACE must be returned to zero (or the pre-disturbance ACE if less than
zero) when the proposed BAL-001 standard states that operation within a wide range is reasonable
assuming frequency is near 60 Hz. In other words, if a BA is within the allowed operating range with
an ACE of -300 under BAL-001-1, why is recovery required to be to zero? As an example, a
moderate-sized BA is operating with a positive 200 ACE prior to the event when it experiences the
loss of a 500 MW unit, causing its ACE to drop to a negative 300. Assuming frequency is near 60
hertz, a negative 300 ACE may be well within the boundaries established by the proposed BAL-001-1.
Why does an entity need to activate reserves to drive its ACE back to zero when its ACE is within the
acceptable operating range established under BAL-001-1? As currently structured, the operator must
call on the contingency reserves to drive the ACE up and then would make a reasonable decision to
end the use of the contingency reserves as soon as the ACE hits zero, allowing the reserves to back
off and therefore be restored while the ACE drops back to negative 300. It appears that the drafting
team needs to more clearly align the requirements in these two standards. To be clear, Xcel Energy
support moving from CPS2 to the RBC and believes this standard needs to recognize the changes

brought about by that modification. A more appropriate level of requirement would be that the BA
move back within the RBC limits within a specified time frame, such as 15 minutes. Finally, Xcel
Energy believes this requirement would be better within a single standard with the requirements of
BAL-001 and BAL-013. Finally, a requirement to get ACE to a specific level, regardless of any BES
limit being exceeded is unreasonable an illadvised. Also there needs to be a descriptor of how the
RSG can demonstrate recovery (i.e. a combined ACE, or can each BA in the RSG show noncoincidental recovery)?
No
The wording of the measure is reasonable but the result is not due to the wording in the requirement.
If the drafting team addresses our concerns with the requirement, the language in the measurement
is reasonable. If the drafting team does not change the requirement to address Xcel Energy’s
concerns, then the measurement needs to be clearer as to what constitutes implementation of the
plan and not just performance.
No
There is no discussion related to the proposed definitions. Without any discussion of these very
important items, the background document fails to provide sufficient support for the standard.
None known at this time.
It is unclear why the Implementation plan mentions retiring BAL-002-0. That standard is no longer
included in the NERC standards documentation and is shown as inactive effective 3/31/2012. Xcel
Energy also reiterates its concern with the concept of multiple standards with requirements that have
a high level of interaction. It is better to have multiple requirements under a single standard and for
that reason, Xcel Energy recommends that the drafting team move all requirements in BAL-001, 002
and 013 (to the extent they move forward) into a single standard.
Group
Western Electricity Coordinating Council
Steve Rueckert
No
1. Balancing Contingency Event – Item C is part of regulating reserve; the definition is very wordy. 2.
Most Severe Single Contingency a) this definition should be applicable to both BA and RSG. b) The
phrase” greatest loss of activated DCLM” is confusing. If the intent is to refer to the return of DCLM
then WECC recommends that it be changed to “unexpected reactivation of DCLM”. If it is intended to
refer to an amount of DCLM no longer being available to activate, did the SDT consider "Loss of or
sudden reactivation of DCLM?" c) The definition of MSSC does not refer to a single event. As written
multiple Balancing Contingency Events could be MSSC. 3. Reportable Contingency Event: The
definition should include RSG. Is a BA's RCE an RCE for the Reserve Sharing Group in which the BA
resides? Is 80% of a BA's MSSC reportable if it is less than 80% of the RSG's MSSC? 4. Contingency
Reserve Restoration Period: the proposed standard removes the requirement to restore the reserves.
The last part of the definition should be deleted, “during which the amount of Contingency Reserve
deployed to recover from a Balancing Contingency Event is to be restored”, otherwise, it appears to
be an attempt to put a requirement into a definition.
No
1. As written the requirement is not easy to comprehend. The requirement needs to be simplified in
language and maybe provide some examples in an attachment or background document 2. The
requirement should be to meet the ACE recovery within 15 minute not to implement the Contingency
Reserve (CR) plan or the two should be separate requirements. As written, if a BA met the 15 minute
recovery requirement but used a resource not in its CR plan it could be a violation of the requirement.
3. The SDT needs to clarify how a RSG can demonstrate ACE recovery whether its recovery of
combined ACE of all BAs in the RSG or if its recovery of individual ACEs for BAs in the RSG.
No

There is no discussion related to the proposed definitions. Without any discussion of these very
important items, the background document fails to provide sufficient support for the standard. The
document also states it establishes a ceiling for the Contingency Reserve . It’s not clear where the
ceiling is established in the standard.
Order 693 directed NERC to inlcude a requirement that explicity explicitly allows demand-side
management (DSM) to be used as a resource for contingency reserves. This does not appear to have
been included in the proposed standard or definitions.
Rather than a separate standard, BAL-013, did the SDT consider including the single requirement of
BAL-013 in BAL-002?

Comment Form

Project 2010-14.1 Balancing Authority Reliability-based Control
BAL-002-íContingency Reserve for Recovery from a Contingency Event

Please do not use this form to submit comments on the proposed revisions to BAL-002-2 Contingency
Reserve for Recovery from a Contingency Event. Comments must be submitted using the electronic
comment form by 8 p.m. July 3, 2012. If you have questions please contact Darrel Richardson (email)
or by telephone at (609) 613-1848.
Background Information:

Since loss of generation occurrences so often impacts all Balancing Authorities throughout an
Interconnection, BAL-002 was created to specify recovery actions and time frames. The original
Standards Authorization Request (SAR) approved by the Industry presumes there is presently sufficient
contingency reserve in all the North American Interconnections. The underlying goal of the SAR was to
update the Standard to make the measurement process more objective and to provide information to
the Balancing Authority or Reserve Sharing Group such that the parties would better understand the
use of contingency reserve to balance resources and demand following a Reportable Contingency
Event. The primary objective of BAL-002-2 is to measure the success of implementing a Contingency
Reserve Plan.

You do not have to answer all questions. Enter All Comments in Simple Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. The BARC SDT has developed five new terms to be used with this standard.
Balancing Contingency Event:
Any single event described in subsections (A), (B), or (C) below, or any series of such
otherwise single events with each separated from the next by less than one minute.
A. Sudden Loss of Generation:
a. Due to
i. unit tripping,
ii. loss of generator interconnection facilities resulting in isolation of the
generator from the Bulk Electric System or from the Responsible
Entity’s electric system, or
iii. sudden unplanned outage of transmission facilities;
b. And, that causes an unexpected change to the Responsible Entity’s ACE;
c. Provided, however, that normal, recurring operating characteristics of a unit
do not constitute sudden or unanticipated losses and may not be subject to
this definition.
B. Sudden Loss of Non-Interruptible Import:
a. A sudden loss of a non-interruptible import, due to forced outage of
transmission equipment, that causes an unexpected change to the
Responsible Entity’s ACE.
C. Unexpected Failure of Generation to Maintain or Increase:
a. Due to
i. inability to start a unit the Responsible Entity planned to bring online
at that time (for reasons other than lack of fuel), or
ii. internal plant equipment problems that force the generator to be
ramped down or taken offline;
b. And that, even if not an immediate cause of an unexpected change to the
Responsible Entity’s ACE, will, in the Responsible Entity’s judgment, leave
the Responsible Entity unable to maintain its ACE following the failure unless
it deploys contingency reserve.
Most Severe Single Contingency (MSSC):
The Balancing Contingency Event that would result in the greatest loss (measured in MW) of
generation output used by the Balancing Authority, or the greatest loss of activated Direct
Control Load Management used by the Balancing Authority, to meet firm system load and
non-interruptible export obligation (excluding export obligation for which contingency
reserve obligations are being met by the sink Balancing Authority).

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event
Comment Form

2

Reportable Contingency Event:
Any Balancing Contingency Event greater than or equal to the lesser amount of 80 percent
of the Balancing Authority’s Most Severe Single Contingency or 500 MW.
Contingency Event Recovery Period:
A period not exceeding 15 minutes following the start of the Balancing Contingency Event.
The start of the Balancing Contingency Event is the point in time where the first change in
MW is observed due to the event.
Contingency Reserve Restoration Period:
A period not exceeding 90 minutes following the end of the Contingency Event Recovery
Period, during which the Amount of Contingency Reserve deployed to recover from a
Balancing Contingency Event is to be restored.
Pre-Reportable Contingency Event ACE Value:
The value of ACE immediately prior to a Reportable Contingency Event when there are no
previous Reportable Contingency Events for which the Contingency Event Recovery Period
is not yet completed,
or
The value of ACE that the Balancing Authority or Reserve Sharing Group must attain to fully
meet its ACE recovery requirement with respect to the immediately previous Reportable
Contingency Event for which the Contingency Event Recovery Period is not yet completed.
Do you agree with the proposed definitions in this standard? If not, please explain in the comment
area below.
Yes
No
Comments: The Balancing Contingency Event definition should explicit state that generation
rejection due to special protection systems (SPS) operation should not be considered as a Balancing
Contingency Event since it is an anticipated and voluntary action.
Also if energy is being wheeled from BA1 to BA3 through BA2 and a contingency occurs resulting
generation in BA1 being isolated from the Bulk Electric System, it is not explicit if it is the sinking
Balancing Authority (BA3) or the wheeling Balancing Authority (BA2) that is experiencing the
resource loss.
Finally, the Most Single Severe Contingency definition does not put any guidelines in how frequent
it needs to be evaluated. For example, the MSSC evaluated on a complete system could be quite

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event
Comment Form

3

higher from a MSSC evaluated when transmission outages are occurring. There is a risk that a BA
would not carry enough reserves to cover that contingency.
2. The proposed Purpose Statement for the draft standard is:
To ensure the Balancing Authority or Reserve Sharing Group utilizes its Contingency Reserve to
balance resources and demand and return the Balancing Authority’s or Reserve Sharing Group’s
Area Control Error to defined values (subject to applicable limits) following a Reportable
Contingency Event.
Do you agree with this purpose statement? If not, please explain in the comment area below.
Yes
No
Comments:
3. The BARC SDT has developed Requirement R1 to determine whether a Balancing Authority (BA)
or Reserve Sharing Group (RSG) has implemented its Contingency Reserve plan and determine
whether a BA or RSG met ACE recovery equal to the BA’s or RSG’s Most Severe Single
Contingency.
R1. Each Balancing Authority or Reserve Sharing Group experiencing a Reportable Contingency
Event shall implement its Contingency Reserve plan so that the Balancing Authority or Reserve
Sharing Group can demonstrate that, within the Contingency Event Recovery Period:
x

ͻ

The Balancing authority or Reserve Sharing Group returned its ACE to
ƒ

Zero, less the sum of the magnitudes of all subsequent Balancing
Contingency Events that occur within the Contingency Event Recovery
Period, if its ACE just prior to the Reportable Contingency Event was positive
or equal to zero, or

ƒ

Its Pre-Reportable Contingency Event ACE Value, less the sum of the
magnitudes of all subsequent Balancing Contingency Events that occur within
the Contingency Event Recovery Period, if its ACE just prior to the Reportable
Contingency Event was negative.

Provided, however, that in either of the foregoing cases, if the Reportable
Contingency Event (individually or when combined with any previous Balancing
Contingency Events that have not completed their Contingency Reserve Restoration
Periods) exceeded the Balancing Authority’s or Reserve Sharing Group’s Most Severe
Single Contingency (MSSC), then the Balancing Authority or Reserve Sharing Group
need only demonstrate ACE recovery of at least equal to its MSSC, less the sum of
the magnitudes of all Previous Balancing Contingency Events that have not
completed their Contingency Reserve Restoration Periods.

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event
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4

Do you agree with this Requirement? If not, please explain in the comment area below.
Yes
No
Comments: When a BA experiences a Reportable Contingency Event that is larger than it’s MSSC, it
only needs to demonstrate that it activated reserves equal to it’s MSSC. However, there is no
requirement or other mechanism to validate if the MSSC was correctly evaluated at first. Based on
the definitions above, the only reason why a MSSC could be greater than a Reportable Contingency
Event is if non firm load or non firm exports were supported by the resource that was lost.
4. The BARC SDT has developed a Measure for the proposed Requirement within this standard.
Do you agree with the proposed Measure in this standard? If not, please explain in the
comment area.
Yes
No
Comments:
5. The BARC SDT has developed a document “BAL-002-2 Contingency Reserve for Recovery from a
Balancing Contingency Event Standard Background Document” which provides information
behind the development of the standard. Do you agree that this new document provides
sufficient clarity as to the development of the standard? If not, please explain in the comment
area.
Yes
No
Comments:
6. If you are aware of any conflicts between the proposed standard and any regulatory function,
rule order, tariff, rate schedule, legislative requirement, or agreement please identify the
conflict here.
Comments:
7. Do you have any other comment on BAL-002-2, not expressed in the questions above, for the
BARC SDT?
Comments:

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event
Comment Form

5

Comment Form

Project 2010-14.1 Balancing Authority Reliability-based Control
BAL-002-2 í Contingency Reserve for Recovery from a Contingency Event

Please do not use this form to submit comments on the proposed revisions to BAL-002-2 Contingency
Reserve for Recovery from a Contingency Event. Comments must be submitted using the electronic
comment form by 8 p.m. July 3, 2012. If you have questions please contact Darrel Richardson (email)
or by telephone at (609) 613-1848.
Background Information:

Since loss of generation occurrences so often impacts all Balancing Authorities throughout an
Interconnection, BAL-002 was created to specify recovery actions and time frames. The original
Standards Authorization Request (SAR) approved by the Industry presumes there is presently sufficient
contingency reserve in all the North American Interconnections. The underlying goal of the SAR was to
update the Standard to make the measurement process more objective and to provide information to
the Balancing Authority or Reserve Sharing Group such that the parties would better understand the
use of contingency reserve to balance resources and demand following a Reportable Contingency
Event. The primary objective of BAL-002-2 is to measure the success of implementing a Contingency
Reserve Plan.

You do not have to answer all questions. Enter All Comments in Simple Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. The BARC SDT has developed five new terms to be used with this standard.
Balancing Contingency Event:
Any single event described in subsections (A), (B), or (C) below, or any series of such
otherwise single events with each separated from the next by less than one minute.
A. Sudden Loss of Generation:
a. Due to
i. unit tripping,
ii. loss of generator interconnection facilities resulting in isolation of the
generator from the Bulk Electric System or from the Responsible
Entity’s electric system, or
iii. sudden unplanned outage of transmission facilities;
b. And, that causes an unexpected change to the Responsible Entity’s ACE;
c. Provided, however, that normal, recurring operating characteristics of a unit
do not constitute sudden or unanticipated losses and may not be subject to
this definition.
B. Sudden Loss of Non-Interruptible Import:
a. A sudden loss of a non-interruptible import, due to forced outage of
transmission equipment, that causes an unexpected change to the
Responsible Entity’s ACE.
C. Unexpected Failure of Generation to Maintain or Increase:
a. Due to
i. inability to start a unit the Responsible Entity planned to bring online
at that time (for reasons other than lack of fuel), or
ii. internal plant equipment problems that force the generator to be
ramped down or taken offline;
b. And that, even if not an immediate cause of an unexpected change to the
Responsible Entity’s ACE, will, in the Responsible Entity’s judgment, leave
the Responsible Entity unable to maintain its ACE following the failure unless
it deploys contingency reserve.
Most Severe Single Contingency (MSSC):
The Balancing Contingency Event that would result in the greatest loss (measured in MW) of
generation output used by the Balancing Authority, or the greatest loss of activated Direct
Control Load Management used by the Balancing Authority, to meet firm system load and
non-interruptible export obligation (excluding export obligation for which contingency
reserve obligations are being met by the sink Balancing Authority).

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event
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2

Reportable Contingency Event:
Any Balancing Contingency Event greater than or equal to the lesser amount of 80 percent
of the Balancing Authority’s Most Severe Single Contingency or 500 MW.
Contingency Event Recovery Period:
A period not exceeding 15 minutes following the start of the Balancing Contingency Event.
The start of the Balancing Contingency Event is the point in time where the first change in
MW is observed due to the event.
Contingency Reserve Restoration Period:
A period not exceeding 90 minutes following the end of the Contingency Event Recovery
Period, during which the Amount of Contingency Reserve deployed to recover from a
Balancing Contingency Event is to be restored.
Pre-Reportable Contingency Event ACE Value:
The value of ACE immediately prior to a Reportable Contingency Event when there are no
previous Reportable Contingency Events for which the Contingency Event Recovery Period
is not yet completed,
or
The value of ACE that the Balancing Authority or Reserve Sharing Group must attain to fully
meet its ACE recovery requirement with respect to the immediately previous Reportable
Contingency Event for which the Contingency Event Recovery Period is not yet completed.
Do you agree with the proposed definitions in this standard? If not, please explain in the comment
area below.
Yes
No
Comments:
2. The proposed Purpose Statement for the draft standard is:
To ensure the Balancing Authority or Reserve Sharing Group utilizes its Contingency Reserve to
balance resources and demand and return the Balancing Authority’s or Reserve Sharing Group’s
Area Control Error to defined values (subject to applicable limits) following a Reportable
Contingency Event.
Do you agree with this purpose statement? If not, please explain in the comment area below.
Yes
No
Comments:

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event
Comment Form

3

3. The BARC SDT has developed Requirement R1 to determine whether a Balancing Authority (BA)
or Reserve Sharing Group (RSG) has implemented its Contingency Reserve plan and determine
whether a BA or RSG met ACE recovery equal to the BA’s or RSG’s Most Severe Single
Contingency.
R1. Each Balancing Authority or Reserve Sharing Group experiencing a Reportable Contingency
Event shall implement its Contingency Reserve plan so that the Balancing Authority or Reserve
Sharing Group can demonstrate that, within the Contingency Event Recovery Period:
x

ͻ

The Balancing authority or Reserve Sharing Group returned its ACE to
ƒ

Zero, less the sum of the magnitudes of all subsequent Balancing
Contingency Events that occur within the Contingency Event Recovery
Period, if its ACE just prior to the Reportable Contingency Event was positive
or equal to zero, or

ƒ

Its Pre-Reportable Contingency Event ACE Value, less the sum of the
magnitudes of all subsequent Balancing Contingency Events that occur within
the Contingency Event Recovery Period, if its ACE just prior to the Reportable
Contingency Event was negative.

Provided, however, that in either of the foregoing cases, if the Reportable
Contingency Event (individually or when combined with any previous Balancing
Contingency Events that have not completed their Contingency Reserve Restoration
Periods) exceeded the Balancing Authority’s or Reserve Sharing Group’s Most Severe
Single Contingency (MSSC), then the Balancing Authority or Reserve Sharing Group
need only demonstrate ACE recovery of at least equal to its MSSC, less the sum of
the magnitudes of all Previous Balancing Contingency Events that have not
completed their Contingency Reserve Restoration Periods.

Do you agree with this Requirement? If not, please explain in the comment area below.
Yes
No
Comments:
The requirement appears to be missing an element. The requirement is obligating the entity to
implement its Contingency Reserve plan but there is no requirement to establish/put a plan in
place.
Also, the VRF and Time Horizon are blank. Will these be filled in later?

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event
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4

4. The BARC SDT has developed a Measure for the proposed Requirement within this standard.
Do you agree with the proposed Measure in this standard? If not, please explain in the
comment area.
Yes
No
Comments:
The semi colon in the second line should be deleted.
5. The BARC SDT has developed a document “BAL-002-2 Contingency Reserve for Recovery from a
Balancing Contingency Event Standard Background Document” which provides information
behind the development of the standard. Do you agree that this new document provides
sufficient clarity as to the development of the standard? If not, please explain in the comment
area.
Yes
No
Comments:
This document restates the Requirement and only has a brief paragraph at the end describing the
background and rationale. This does not provide any significant support to the Requirement.
6. If you are aware of any conflicts between the proposed standard and any regulatory function,
rule order, tariff, rate schedule, legislative requirement, or agreement please identify the
conflict here.
Comments:

7. Do you have any other comment on BAL-002-2, not expressed in the questions above, for the
BARC SDT?
Comments:
Compliance, 1.2. Data Retention – the word ‘previous’ should be added before the words ‘three
calendar years’.

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5

Compliance, 1.4. Additional Compliance Information – the third paragraph under this section seems
to need more context and more detail. Perhaps add a cross reference to the definition of
Reportable Contingency Event which mentions the 80% threshold.
See comments related to 5. Effective Date provided in the BAL-001 comment form.

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event
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6

Comment Form

Project 2010-14.1 Balancing Authority Reliability-based Control
BAL-002-2 í Contingency Reserve for Recovery from a Contingency Event

Please do not use this form to submit comments on the proposed revisions to BAL-002-2 Contingency
Reserve for Recovery from a Contingency Event. Comments must be submitted using the electronic
comment form by 8 p.m. July 3, 2012. If you have questions please contact Darrel Rh
R
ichardson (email) or by telephone at (609) 613-1848.
Background Information:

Since loss of generation occurrences so often impacts all Balancing Authorities throughout an
Interconnection, BAL-002 was created to specify recovery actions and time frames. The original
Standards Authorization Request (SAR) approved by the Industry presumes there is presently sufficient
contingency reserve in all the North American Interconnections. The underlying goal of the SAR was to
update the Standard to make the measurement process more objective and to provide information to
the Balancing Authority or Reserve Sharing Group such that the parties would better understand the
use of contingency reserve to balance resources and demand following a Reportable Contingency
Event. The primary objective of BAL-002-2 is to measure the success of implementing a Contingency
Reserve Plan.

You do not have to answer all questions. Enter All Comments in Simple Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. The BARC SDT has developed five new terms to be used with this standard.
Balancing Contingency Event:
Any single event described in subsections (A), (B), or (C) below, or any series of such
otherwise single events with each separated from the next by less than one minute.
A. Sudden Loss of Generation:
a. Due to
i. unit tripping,
ii. loss of generator interconnection facilities resulting in isolation of the
generator from the Bulk Electric System or from the Responsible
Entity’s electric system, or
iii. sudden unplanned outage of transmission facilities;
b. And, that causes an unexpected change to the Responsible Entity’s ACE;
c. Provided, however, that normal, recurring operating characteristics of a unit
do not constitute sudden or unanticipated losses and may not be subject to
this definition.
B. Sudden Loss of Non-Interruptible Import:
a. A sudden loss of a non-interruptible import, due to forced outage of
transmission equipment, that causes an unexpected change to the
Responsible Entity’s ACE.
C. Unexpected Failure of Generation to Maintain or Increase:
a. Due to
i. inability to start a unit the Responsible Entity planned to bring online
at that time (for reasons other than lack of fuel), or
ii. internal plant equipment problems that force the generator to be
ramped down or taken offline;
b. And that, even if not an immediate cause of an unexpected change to the
Responsible Entity’s ACE, will, in the Responsible Entity’s judgment, leave
the Responsible Entity unable to maintain its ACE following the failure unless
it deploys contingency reserve.
Most Severe Single Contingency (MSSC):
The Balancing Contingency Event that would result in the greatest loss (measured in MW) of
generation output used by the Balancing Authority, or the greatest loss of activated Direct
Control Load Management used by the Balancing Authority, to meet firm system load and

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event
Comment Form

2

non-interruptible export obligation (excluding export obligation for which contingency
reserve obligations are being met by the sink Balancing Authority).
Reportable Contingency Event:
Any Balancing Contingency Event greater than or equal to the lesser amount of 80 percent
of the Balancing Authority’s Most Severe Single Contingency or 500 MW.
Contingency Event Recovery Period:
A period not exceeding 15 minutes following the start of the Balancing Contingency Event.
The start of the Balancing Contingency Event is the point in time where the first change in
MW is observed due to the event.
Contingency Reserve Restoration Period:
A period not exceeding 90 minutes following the end of the Contingency Event Recovery
Period, during which the Amount of Contingency Reserve deployed to recover from a
Balancing Contingency Event is to be restored.
Pre-Reportable Contingency Event ACE Value:
The value of ACE immediately prior to a Reportable Contingency Event when there are no
previous Reportable Contingency Events for which the Contingency Event Recovery Period
is not yet completed,
or
The value of ACE that the Balancing Authority or Reserve Sharing Group must attain to fully
meet its ACE recovery requirement with respect to the immediately previous Reportable
Contingency Event for which the Contingency Event Recovery Period is not yet completed.
Do you agree with the proposed definitions in this standard? If not, please explain in the comment
area below.
Yes
No
Comments: We do not agree with the 500MW specification in the definition of “Reportable
Contingency Event”. We suggest that each Interconnection should have a unique reporting level
based on frequency impact. For example, the reporting threshold could be a MW value that has
an impact to frequency in that interconnection. This should result in a table with four (4) MW
values, one for reporting in each Interconnection.
We suggest changing the definition of “Reportable Contingency Event” to “Reportable Balancing
Contingency Event”. Will this replace the existing glossary item “Reportable Disturbance”?

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We suggest that Direct Control Load Management should be taken out of the MSSC definition
and rolled into the definition of Balancing Contingency Event. We are concerned that an event
that is not considered as a credible event can be construed as an MSCC for an entity.
We suggest the “Contingency Reserves” definition needs to be addressed. The current NERC
Glossary references BAL-002-1 for definition and this may need to be changed to BAL-012-1?
We suggest deleting Paragraph C of “Balancing Contingency Event”.
We suggest the word “Reportable” be inserted before “Balancing Contingency Event” in both the
Contingency Event Recovery Period and the Contingency Event Restoration Period definitions.
We also suggest that “Sudden Loss” be clarified to occur within a one (1) minute time frame.
2. The proposed Purpose Statement for the draft standard is:
To ensure the Balancing Authority or Reserve Sharing Group utilizes its Contingency Reserve to
balance resources and demand and return the Balancing Authority’s or Reserve Sharing Group’s
Area Control Error to defined values (subject to applicable limits) following a Reportable
Contingency Event.
Do you agree with this purpose statement? If not, please explain in the comment area below.
Yes
No
Comments:
3. The BARC SDT has developed Requirement R1 to determine whether a Balancing Authority (BA)
or Reserve Sharing Group (RSG) has implemented its Contingency Reserve plan and determine
whether a BA or RSG met ACE recovery equal to the BA’s or RSG’s Most Severe Single
Contingency.
R1. Each Balancing Authority or Reserve Sharing Group experiencing a Reportable Contingency
Event shall implement its Contingency Reserve plan so that the Balancing Authority or Reserve
Sharing Group can demonstrate that, within the Contingency Event Recovery Period:
x

The Balancing authority or Reserve Sharing Group returned its ACE to
ƒ

Zero, less the sum of the magnitudes of all subsequent Balancing
Contingency Events that occur within the Contingency Event Recovery
Period, if its ACE just prior to the Reportable Contingency Event was positive
or equal to zero, or

ƒ

Its Pre-Reportable Contingency Event ACE Value, less the sum of the
magnitudes of all subsequent Balancing Contingency Events that occur within

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event
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4

the Contingency Event Recovery Period, if its ACE just prior to the Reportable
Contingency Event was negative.
ͻ

Provided, however, that in either of the foregoing cases, if the Reportable
Contingency Event (individually or when combined with any previous Balancing
Contingency Events that have not completed their Contingency Reserve Restoration
Periods) exceeded the Balancing Authority’s or Reserve Sharing Group’s Most Severe
Single Contingency (MSSC), then the Balancing Authority or Reserve Sharing Group
need only demonstrate ACE recovery of at least equal to its MSSC, less the sum of
the magnitudes of all Previous Balancing Contingency Events that have not
completed their Contingency Reserve Restoration Periods.

Do you agree with this Requirement? If not, please explain in the comment area below.
Yes
No
Comments: R1 should not require the implementation of the Contingency Reserve Plan. ACE
recovery is the goal, not the implementation of the plan.
4. The BARC SDT has developed a Measure for the proposed Requirement within this standard.
Do you agree with the proposed Measure in this standard? If not, please explain in the
comment area.
Yes
No
Comments:
5. The BARC SDT has developed a document “BAL-002-2 Contingency Reserve for Recovery from a
Balancing Contingency Event Standard Background Document” which provides information
behind the development of the standard. Do you agree that this new document provides
sufficient clarity as to the development of the standard? If not, please explain in the comment
area.
Yes
No
Comments: See comments in question 1.
6. If you are aware of any conflicts between the proposed standard and any regulatory function,
rule order, tariff, rate schedule, legislative requirement, or agreement please identify the
conflict here.
Comments: No

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7. Do you have any other comment on BAL-002-2, not expressed in the questions above, for the
BARC SDT?
Comments: We suggest the SDT explain the absence of reporting requirements. Also explain
why the data retention period was extended to 3 years from the current 1 year requirement.

“The comments expressed herein represent a consensus of the views of the above named members of
the SERC OC Standards Review group only and should not be construed as the position of SERC
Reliability Corporation, its board or its officers.”

Members participating in the development of comments:
Jeff Harrison
Stuart Goza
Gerry Beckerle
Cindy martin
Andy Burch
Larry Akens
Devan Hoke
Wayne Van Liere
Kelly Casteel
John Jackson
Brad Gordon
Randi Heise
Dan Roethemeyer
Jim Case
Bill Thigpen
Jake Miller
Steve Corbin
Ena Agbedia
Ron Carlsen
Vicky Budreau
Shammara Hasty
Melinda Montgomery
Terry Coggins
J.T. Wood

[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event
Comment Form

6

Antonio Grayson
John Troha

[email protected]
[email protected]

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event
Comment Form

7

Standard BAL-001-1 – Real Power Balancing Control Performance

Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. The SAR for Project 2007-18, Reliability Based Controls, was posted for a 30-day formal
comment period on May 15, 2007.
2. A revised SAR for Project 2007-05, Reliability Based Controls, was posted for a second
30-day formal comment period on September 10, 2007.
3. The Standards Committee approved Project 2007-18, Reliability Based Controls, to be
moved to standard drafting on December 11, 2007.
4. The SAR for Project 2007-05, Balancing Authority Controls, was posted for a 30-day
formal comment period on July 3, 2007.
5. The Standards Committee approved Project 2007-05, Balancing Authority Controls, to
be moved to standard drafting on January 18, 2008.
6. The Standards Committee approved the merger of Project 2007-05, Balancing Authority
Controls, and Project 2007-18, Reliability-based Controls, as Project 2010-14, Balancing
Authority Reliability-based Controls, on July 28, 2010.
7. The NERC Standards Committee approved breaking Project 2010-14, Balancing
Authority Reliability-based Controls, into two phases; and moving Phase 1 (Project 201014.1, Balancing Authority Reliability-based Controls – Reserves) into formal standards
development on July 13, 2011.
Proposed Action Plan and Description of Current Draft:
This is the first posting of the proposed new standard. This proposed draft standard will be
posted for a 30-day formal comment period beginning on June 4, 2012 through July 3, 2012.
Future Development Plan:
Anticipated Actions
1. Second posting
2. Initial Ballot

Anticipated Date
October/November
2012
November 2012

3. Recirculation Ballot

March 2013

4. NERC BOT adoption.

March 2013

BAL-001-1 Draft 1
June 4, 2012

Page 1 of 11

Standard BAL-001-1 – Real Power Balancing Control Performance
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Balancing Authority ACE Limit (BAAL): The limit beyond which a Balancing Authority
contributes more than its share of Interconnection frequency control reliability risk. This
definition applies to a high limit (BAAL High ) and a low limit (BAAL Low ).
Reporting ACE: The scan rate values of a Balancing Authority’s Area Control Error (ACE)
measured in MW, as defined in BAL-001, which includes the difference between the Balancing
Authority’s actual Interchange and its scheduled Interchange, plus its Frequency Bias obligation,
plus any known meter error.
Interconnection: When capitalized, any one of the four major electric system networks in North
America: Eastern, Western, Texas and Quebec.

BAL-001-1 Draft 1
June 4, 2012

Page 2 of 11

Standard BAL-001-1 – Real Power Balancing Control Performance
A. Introduction
1.

Title:

Real Power Balancing Control Performance

2.

Number:

BAL-001-1

3.

Purpose:

To control Interconnection frequency within defined limits.

4.

Applicability:
4.1. Balancing Authority
4.1.1 A Balancing Authority providing Overlap Regulation Service to another
Balancing Authority calculates its CPS1 performance after combining its
Reporting ACE and Frequency Bias Settings with the Reporting ACE, and
Frequency Bias Settings of the Balancing Authority receiving the Regulation
Service.
4.1.2 A Balancing Authority providing Overlap Regulation Service to another
Balancing Authority calculates its BAAL performance after combining its
Frequency Bias Setting with the Frequency Bias Setting of the Balancing
Authority receiving Regulation Service.
4.1.3 A Balancing Authority receiving Overlap Regulation Service is not subject to
CPS1 or BAAL compliance evaluation.

5.

(Proposed) Effective Date:
5.1.

First day of the first calendar quarter that is six months beyond the date that
this standard is approved by applicable regulatory authorities, or in those
jurisdictions where regulatory approval is not required, the standard becomes
effective the first day of the first calendar quarter that is six months beyond the
date this standard is approved by the NERC Board of Trustees’, or as otherwise
made pursuant to the laws applicable to such ERO governmental authorities.

B. Requirements
R1.

Each Balancing Authority shall operate such that the Balancing Authority’s Control
Performance Standard 1 (CPS1), as calculated in Attachment 1, is greater than or
equal to 100 percent for the applicable Interconnection in which it operates for each
12-month period, evaluated monthly, to support Interconnection frequency.
[Violation Risk Factor: Medium] [Time Horizon: Real-time Operations]

R2.

Each Balancing Authority shall operate such that its clock-minute average of Reporting
ACE does not exceed for more than 30 consecutive clock-minutes its clock-minute
Balancing Authority ACE Limit (BAAL), as calculated in Attachment 2, for the
applicable Interconnection in which it operates to support Interconnection
frequency.[Violation Risk Factor: Medium] [Time Horizon: Real-time Operations]

C. Measures

BAL-001-1 Draft 1
June 4, 2012

Page 3 of 11

Standard BAL-001-1 – Real Power Balancing Control Performance
M1. Each Balancing Authority shall provide evidence, upon request; such as dated
calculation output from spreadsheets, Energy Management System logs, software
programs, or other evidence (either in hard copy or electronic format) to demonstrate
compliance with Requirement R1.
M2. Each Balancing Authority shall provide evidence, upon request; such as dated
calculation output from spreadsheets, Energy Management System logs, software
programs, or other evidence (either in hard copy or electronic format) to demonstrate
compliance with Requirement R2.
D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
The regional entity is the compliance enforcement authority, except where the
responsible entity works for the regional entity. Where the responsible entity
works for the regional entity, the regional entity will establish an agreement with
the ERO, or another entity approved by the ERO and FERC (i.e., another regional
entity), to be responsible for compliance enforcement.
1.2. Data 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 compliance enforcement authority may ask an entity to
provide other evidence to show that it was compliant for the full-time period
since the last audit.
The Balancing Authority shall retain data or evidence to show compliance for the
current year, plus three previous calendar years unless, directed by its
compliance enforcement authority, to retain specific evidence for a longer
period of time as part of an investigation. Data required for the calculation of
Reporting ACE, CPS1, and BAAL shall be retained in digital format at the same
scan rate at which the Reporting Ace is calculated for the current year, plus three
previous calendar years.
If a Balancing Authority is found noncompliant, it shall keep information related
to the noncompliance until found compliant, or for the time period specified
above, whichever is longer.
The compliance enforcement authority shall keep the last audit records and all
subsequent requested and submitted records.
1.3. Compliance Monitoring and Assessment Processes
Compliance Audits
Self-Certifications

BAL-001-1 Draft 1
June 4, 2012

Page 4 of 11

Standard BAL-001-1 – Real Power Balancing Control Performance
Spot Checking
Compliance Investigation
Self-Reporting
Complaints
1.4. Additional Compliance Information
None.
2.

Violation Severity Levels
R
#

R1

R2

Lower VSL

Moderate VSL

High VSL

Severe VSL

The Balancing
Authority’s area
value of CPS1,
on a rolling 12month basis, is
less than 100
percent but
greater than or
equal to 95
percent for the
applicable
Interconnection.
The Balancing
Authority
exceeded its
clock-minute
BAAL for more
than 30
consecutive
clock minutes
but less than or
equal to 45
consecutive
clock minutes.

The Balancing
Authority’s area
value of CPS1,
on a rolling 12month basis, is
less than 95
percent, but
greater than or
equal to 90
percent for the
applicable
Interconnection.
The Balancing
Authority
exceeded its
clock-minute
BAAL for greater
than 45
consecutive
clock minutes
but less than or
equal to 60
consecutive
clock minutes.

The Balancing
Authority’s area
value of CPS1,
on a rolling 12month basis, is
less than 90
percent, but
greater than or
equal to 85
percent for the
applicable
Interconnection.
The Balancing
Authority
exceeded its
clock-minute
BAAL for greater
than 60
consecutive
clock minutes
but less than or
equal to 75
consecutive
clock minutes.

The Balancing
Authority’s area value
of CPS1, on a rolling 12month basis, is less than
85 percent for the
applicable
Interconnection.

The Balancing Authority
exceeded its clockminute BAAL for greater
than 75 consecutive
clock-minutes.

E. Regional Variances
None.
F. Associated Documents
BAL-001-1, Real Power Balancing Control Performance Standard Background Document
BAL-001-1 Draft 1
June 4, 2012

Page 5 of 11

Standard BAL-001-1 – Real Power Balancing Control Performance
Version History
Version

Date

Action

Change Tracking

0

February 8,
2005

BOT Approval

New

0

April 1, 2005

Effective Implementation Date

New

0

August 8, 2005

Removed “Proposed” from Effective Date

Errata

0

July 24, 2007

Corrected R3 to reference M1 and M2
instead of R1 and R2

Errata

0a

December 19,
2007

Added Appendix 2 – Interpretation of R1
approved by BOT on October 23, 2007

Revised

0a

January 16,
2008

In Section A.2., Added “a” to end of
standard number
In Section F, corrected automatic
numbering from “2” to “1” and removed
“approved” and added parenthesis to
“(October 23, 2007)”

Errata

0

January 23,
2008

Reversed errata change from July 24, 2007

Errata

0.1a

October 29,
2008

Board approved errata changes; updated
version number to “0.1a”

Errata

0.1a

May 13, 2009

Approved by FERC

1

BAL-001-1 Draft 1
June 4, 2012

Inclusion of BAAL and exclusion of CPS2

Revision

Page 6 of 11

Standard BAL-001-1 – Real Power Balancing Control Performance
Attachment 1
Equations Supporting Requirement R1 and Measure M1
CPS1 is calculated as follows:
CPS1 = (2 - CF) * 100%
The frequency-related compliance factor (CF), is a ratio of the accumulating clock-minute
compliance parameters over a 12-month period, divided by the square of the target
frequency bound:
CF =

CF

12 - month

(ɸ1I ) 2

where ɸ1 I is the constant derived from a targeted frequency bound for each
Interconnection as follows:
x

Eastern Interconnection ɸ1I = 0.018 Hz

x

Western Interconnection ɸ1I = 0.0228 Hz

x

ERCOT Interconnection ɸ1I = 0.030 Hz

x

Quebec Interconnection ɸ1I = 0.021 Hz

The rating index CF 12-month is derived from the most recent consecutive 12 months of data.
The accumulating clock-minute compliance parameters are derived from the one-minute
averages of Reporting ACE, Frequency Error, and Frequency Bias Settings.

Reporting ACE is calculated as follows:
Reporting ACE = (NIA оE/S) оϭϬ;&A о&S) оED
Where:
NIA (Net Interchange Actual) is the algebraic sum of actual megawatt transfers
across all Tie Lines and includes Pseudo-Ties. Balancing Authorities directly
connected via asynchronous ties to another Interconnection may include or
exclude megawatt transfers on those tie lines in their actual interchange,
provided they are implemented in the same manner for Net Interchange
Schedule.
NIS (Net Interchange Schedule) is the algebraic sum of all scheduled megawatt
transfers, including Dynamic Schedules, with adjacent Balancing Authorities, and
BAL-001-1 Draft 1
June 4, 2012

Page 7 of 11

Standard BAL-001-1 – Real Power Balancing Control Performance
taking into account the effects of schedule ramps. Balancing Authorities directly
connected via asynchronous ties to another Interconnection may include or
exclude megawatt transfers on those tie lines in their scheduled Interchange,
provided they are implemented in the same manner for Net Interchange Actual.
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, with minimum resolution
of +/- 0.0005 Hz.
FS (Scheduled Frequency) is 60.0 Hz, except during a time correction.
NME (Net Meter Error) is the meter error correction factor and represents the
difference between the integrated hourly average of the net interchange actual
(NIA) and the cumulative hourly net Interchange energy measurement (in
megawatt-hours).
A clock-minute average is the average of the reporting Balancing Authority’s valid
measured variable (i.e., for Reporting ACE and for Frequency Error) for each sampling cycle
during a given clock minute.

§ ACE ·
¸
¨
©  10 B ¹ clock -minute

§ ¦ ACEsampling cycles in clock -minute
¨
¨
nsampling cycles in clock -minute
©
- 10B

·
¸
¸
¹

and,
'Fclock -minute

¦ 'F

sampling cycles in clock - minute

nsampling cycles in clock -minute

The Balancing Authority’s clock-minute compliance factor (CF clock-minute ) calculation is:

CFclock -minute

ª§ ACE ·
º
* 'Fclock -minute »
¸
Ǭ
¬©  10 B ¹ clock -minute
¼

Normally, 60 clock-minute averages of the reporting Balancing Authority’s Reporting ACE
and Frequency Error will be used to compute the hourly average compliance factor (CF clockhour ).

BAL-001-1 Draft 1
June 4, 2012

Page 8 of 11

Standard BAL-001-1 – Real Power Balancing Control Performance

¦ CF

clock - minute

CFclock -hour

nclock -minute samples in hour

The reporting Balancing Authority shall be able to recalculate and store each of the
respective clock-hour averages (CF clock-hour average-month ) and the data samples for each 24hour period (one for each clock-hour; i.e., hour ending (HE) 0100, HE 0200, ..., HE 2400).
To calculate the monthly compliance factor (CF month ):

¦ [(CF
¦ [n

clock - hour

)(none-minute samples in clock -hour )]

days-in - month

CFclock -hour average-month

one - minute samples in clock - hour
days-in month

¦ [(CF

clock - hour average- month

CFmonth

hours -in -day

]

)(none-minute samples in clock -hour averages )]

¦ [n

one - minute samples in clock - hour averages
hours -in day

]

To calculate the 12-month compliance factor (CF 12 month ):
12

¦ (CF

month -i

CF12-month

)(none-minute samples in month i )]

i 1

12

¦ [n

( one - minute samples in month)-i

]

i 1

To ensure that the average Reporting ACE and Frequency Error calculated for any oneminute interval is representative of that time interval, it is necessary that at least 50
percent of both the Reporting ACE and Frequency Error sample data during the oneminute interval is valid. If the recording of Reporting ACE or Frequency Error is interrupted
such that less than 50 percent of the one-minute sample period data is available or valid,
then that one-minute interval is excluded from the CPS1 calculation.
A Balancing Authority providing Overlap Regulation Service to another Balancing Authority
calculates its CPS1 performance after combining its Reporting ACE and Frequency Bias
Settings with the Reporting ACE and Frequency Bias Settings of the Balancing Authority
receiving the Regulation Service.
A Balancing Authority receiving Overlap Regulation Service is not subject to
CPS1compliance evaluation.

BAL-001-1 Draft 1
June 4, 2012

Page 9 of 11

Standard BAL-001-1 – Real Power Balancing Control Performance
Attachment 2
Equations Supporting Requirement R2 and Measure M2

When actual frequency is equal to 60 Hz, BAAL High and BAAL Low do not apply.
When actual frequency is less than 60 Hz, BAAL High does not apply, and BAAL Low is
calculated as:
BAALLow

 10 Bi u FTLLow  60 u

FTLLow  60
FA  60

When actual frequency is greater than 60 Hz, BAAL Low does not apply and the BAAL High is
calculated as:

BAALHigh

 10B u FTL
i

High

 60u

FTL

High

 60

FA  60

Where:
BAAL Low is the Low Balancing Authority ACE Limit (MW)
BAALHigh is the High Balancing Authority ACE Limit (MW)
10 is a constant to convert the Frequency Bias Setting from MW/0.1 Hz to MW/Hz
B i is the Frequency Bias Setting for a Balancing Authority (expressed as MW/0.1 Hz)
FA is the measured frequency in Hz, with a minimum resolution of +/- 0.0005 Hz.
FTLLow is the Low Frequency Trigger Limit (calculated as 60-ϯɸ1I Hz)
FTLHigh is the High Frequency Trigger Limit (calculated as 60+3ɸ1I Hz)
Where ɸ1I is the constant derived from a targeted frequency bound for each
Interconnection as follows:
x

Eastern Interconnection ɸ1I = 0.018 Hz

x

Western Interconnection ɸ1I = 0.0228 Hz

x

ERCOT Interconnection ɸ1I = 0.030 Hz

x

Quebec Interconnection ɸ1I = 0.021 Hz

To ensure that the average actual frequency calculated for any one-minute interval is
representative of that time interval, it is necessary that at least 50% of the actual
frequency sample data during that one-minute interval is valid. If the recording of actual
frequency is interrupted such that less than 50 percent of the one-minute sample period
data is available or valid, then that one-minute interval is excluded from the BAAL
calculation.
BAL-001-1 Draft 1
June 4, 2012

Page 10 of 11

Standard BAL-001-1 – Real Power Balancing Control Performance

A Balancing Authority providing Overlap Regulation Service to another Balancing Authority
calculates its BAAL performance after combining its Frequency Bias Setting with the
Frequency Bias Setting of the Balancing Authority receiving Regulation Service.
A Balancing Authority receiving Overlap Regulation Service is not subject to BAAL
compliance evaluation.

BAL-001-1 Draft 1
June 4, 2012

Page 11 of 11

Comment Form

Project 2010-14.1 Balancing Authority Reliability-based Control
BAL-001-1 í Real Power Balancing Control Performance

Please do not use this form to submit comments on the proposed revisions to BAL-001-1 Real Power
Balancing Control Performance. Comments must be submitted on the electronic comment form by 8
p.m. July 3, 2012. If you have questions please contact Darrel Richardson (email) or by telephone at
(609) 613-1848.
BAL-001-1 Real Power Balancing Control Performance
Background Information:

Control Performance Standard 1 (CPS1) has been retained, and details for calculating CPS1 are included
in Attachment 1. Calculation of Reporting Area Control Error (Reporting ACE) has been clarified, and
details for calculating Reporting ACE are also included in Attachment 1. The Balancing Authority ACE
Limit (BAAL), an interconnection frequency and Balancing Authority ACE measurement, is included in
this standard as Requirement 2 and replaces Control Performance Standard 2 (CPS2). Details for the
calculation of BAAL are included in Attachment 2.
CPS2 was not designed to address Interconnection frequency. Currently, it measures the ability of a
Balancing Authority to maintain its average ACE within a fixed limit of plus or minus a MW value called
L10. To be compliant, a Balancing Authority must demonstrate its average ACE value during a
consecutive ten minute period was within the L10 bound 90 percent of all 10 minute periods over a
one month period. While this standard does require the Balancing Authority to correct its ACE to not
exceed specific bounds, it fails to recognize Interconnection frequency.
BAAL is defined by two equations, BAAL low and BAAL high. BAAL low is for Interconnection frequency
values less than 60 hertz and BAAL high is for Interconnection frequency values greater than 60 hertz.
BAAL values for each Balancing Authority are dynamic and change as Interconnection frequency
changes. For example, as Interconnection frequency moves from 60 hertz, the ACE limit for each
Balancing Authority becomes more restrictive. The BAAL provides each Balancing Authority a dynamic
ACE limit that is a function of Interconnection frequency.
As a proof of concept for the proposed BAAL standard, a BAAL field trial was approved by the NERC
Standards Committee and the Operating Committee. Currently there are 13 Balancing Authorities
participating in the Eastern Interconnection, 26 Balancing Authorities participating in the Western
Interconnection, the ERCOT Balancing Authority, and Quebec. Reliability Coordinators for all
interconnections continue to monitor the performance of those participating Balancing Authorities and

provide information to support monthly analysis of the BAAL field trial. As of the end of September
2011, no reliability issues with the BAAL field trial have been identified by any Reliability Coordinator.
You do not have to answer all questions. Enter All Comments in Simple Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. The BARC SDT has developed two new terms to be used with this standard.
Balancing Authority ACE Limit (BAAL):
The limit beyond which a Balancing Authority contributes more than its share of
Interconnection frequency control reliability risk. This definition applies to a high limit
(BAALHigh) and a low limit (BAALLow).
Reporting ACE:
The scan rate values of a Balancing Authority’s Area Control Error (ACE) measured in
MW as defined in BAL-001 which includes the difference between the Balancing
Authority’s actual interchange and its scheduled interchange plus its frequency bias
obligation plus any known meter error.
Do you agree with the proposed definitions in this standard? If not, please explain in the
comment area below.
Yes
No
Comments:
2. The SDT has modified the definition for the term Interconnection. The new definition
is shown below in redline to show the changes proposed.

Interconnection:
When capitalized, any one of the fourthree major electric system networks in North
America: Eastern, Western, Texas and QuebecERCOT.
Do you agree with this new definition for Interconnection? If not, please explain in the comment
area below.
Yes
No
Comments:
3. The proposed Purpose Statement for the draft standard is:

BAL-001-1 Real Power Balancing Control Performance
Comment Form

2

To control Interconnection frequency within defined limits in support of interconnection
frequency.
Do you agree with this purpose statement? If not, please explain in the comment area below.
Yes
No
Comments:
4. The BARC SDT has developed Requirement R1 to measure how well a Balancing Authority is able
to control its generation and load management programs, as measured by its Area Control Error
(ACE), to supports its Interconnection’s frequency over a rolling one year period.
R1. Each Balancing Authority shall operate such that the Balancing Authority’s Control
Performance Standard 1 (CPS1), as calculated in Attachment 1, is greater than or equal to 100%
for the applicable Interconnection in which it operates for each 12 month period, evaluated
monthly, to support interconnection frequency.
Do you agree with this Requirement? If not, please explain in the comment area below.
Yes
No
Comments:
5. The BARC SDT has developed Requirement R2 to enhance the reliability of each Interconnection
by maintaining frequency within predefined limits under all conditions.
R2. Each Balancing Authority shall operate such that its clock-minute average of Reporting ACE
does not exceed for more than 30 consecutive clock-minutes its clock-minute Balancing
Authority ACE Limit (BAAL), as calculated in Attachment 2, for the applicable Interconnection in
which it operates to support interconnection frequency.
Do you agree with this Requirement? If not, please explain in the comment area below.
Yes
No
Comments:
6. The BARC SDT has developed VRFs for the proposed Requirements within this standard. Do you
agree that these VRFs are appropriately set? If not, please explain in the comment area below.
Yes
No
Comments:

BAL-001-1 Real Power Balancing Control Performance
Comment Form

3

7. The BARC SDT has developed Measures for the proposed Requirements within this standard. Do
you agree with the proposed Measures in this standard? If not, please explain in the comment
area.
Yes
No
Comments:
8. The BARC SDT has developed VSLs for the proposed Requirements within this standard. Do you
agree with these VSLs? If not, please explain in the comment area.
Yes
No
Comments:
9. The BARC SDT has developed a document “BAL-001-1 Real Power Balancing Control Standard
Background Document” which provides information behind the development of the standard.
Do you agree that this new document provides sufficient clarity as to the development of the
standard? If not, please explain in the comment area.
Yes
No
Comments:
10. If you are aware of any conflicts between the proposed standard and any regulatory function,
rule order, tariff, rate schedule, legislative requirement, or agreement please identify the conflict
here.
Comments:
11. Do you have any other comment on BAL-001-1, not expressed in the questions above, for the
BARC SDT?
Comments:

BAL-001-1 Real Power Balancing Control Performance
Comment Form

4

S ta n d a rd BAL-001-0.1a — Re al P owe r Ba la n cin g Co n trol P e rfo rm a n ce
A. Introduction
1.

Title:

Real Power Balancing Control Performance

2.

Number:

BAL-001-0.1a

3.

Purpose:
To maintain Interconnection steady-state frequency within defined limits by
balancing real power demand and supply in real-time.

4.

Applicability:
4.1. Balancing Authorities

5.

Effective Date:

May 13, 2009

B. Requirements
R1.

Each Balancing Authority shall operate such that, on a rolling 12-month basis, the average of
the clock-minute averages of the Balancing Authority’s Area Control Error (ACE) divided by
10B (B is the clock-minute average of the Balancing Authority Area’s Frequency Bias) times
the corresponding clock-minute averages of the Interconnection’s Frequency Error is less than
a specific limit. This limit H is a constant derived from a targeted frequency bound
(separately calculated for each Interconnection) that is reviewed and set as necessary by the
NERC Operating Committee.
ª§ ACEi
AVG Period «¨¨
º
ª§ ACE i ·
«¬©  10 Bi
¸¸ * 'F1 » d12 or
AVG Period «¨¨
12
¼»
¬«©  10 Bi ¹1
The equation for ACE is:

º
·
¸¸ * 'F1 »
»¼
¹1

d1

ACE = (NIA  NIS)  10B (FA  FS)  IME
where:

R2.

x

NIA is the algebraic sum of actual flows on all tie lines.

x

NIS is the algebraic sum of scheduled flows on all tie lines.

x

B is the Frequency Bias Setting (MW/0.1 Hz) for the Balancing Authority. The
constant factor 10 converts the frequency setting to MW/Hz.

x

FA is the actual frequency.

x

FS is the scheduled frequency. FS is normally 60 Hz but may be offset to effect
manual time error corrections.

x

IME is the meter error correction factor typically estimated from the difference between
the integrated hourly average of the net tie line flows (NIA) and the hourly net
interchange demand measurement (megawatt-hour). This term should normally be
very small or zero.

Each Balancing Authority shall operate such that its average ACE for at least 90% of clockten-minute periods (6 non-overlapping periods per hour) during a calendar month is within a
specific limit, referred to as L10.

AVG10 minute ( ACEi ) d L10

Page 1 of 7

S ta n d a rd BAL-001-0.1a — Re al P owe r Ba la n cin g Co n trol P e rfo rm a n ce
where:
L10= 1.65  10

( 10 Bi )( 10 Bs )

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, H10, is the same for every Balancing Authority Area within an
Interconnection, and Bs is the sum of the Frequency Bias Settings of the Balancing Authority
Areas in the respective Interconnection. For Balancing Authority Areas with variable bias, this
is equal to the sum of the minimum Frequency Bias Settings.
R3.

Each Balancing Authority providing Overlap Regulation Service shall evaluate Requirement
R1 (i.e., Control Performance Standard 1 or CPS1) and Requirement R2 (i.e., Control
Performance Standard 2 or CPS2) using the characteristics of the combined ACE and
combined Frequency Bias Settings.

R4.

Any Balancing Authority receiving Overlap Regulation Service shall not have its control
performance evaluated (i.e. from a control performance perspective, the Balancing Authority
has shifted all control requirements to the Balancing Authority providing Overlap Regulation
Service).

C. Measures
M1. Each Balancing Authority shall achieve, as a minimum, Requirement 1 (CPS1) compliance of
100%.
CPS1 is calculated by converting a compliance ratio to a compliance percentage as follows:
CPS1 = (2 - CF) * 100%
The frequency-related compliance factor, CF, is a ratio of all one-minute compliance
parameters accumulated over 12 months divided by the target frequency bound:

CF

CF12  month
(1 ) 2

where:H1 is defined in Requirement R1.
The rating index CF12-month is derived from 12 months of data. The basic unit of data comes
from one-minute averages of ACE, Frequency Error and Frequency Bias Settings.
A clock-minute average is the average of the reporting Balancing Authority’s valid measured
variable (i.e., for ACE and for Frequency Error) for each sampling cycle during a given clockminute.

§ ACE ·
¸
¨
©  10 B ¹ clock -minute

'Fclock -minute

§ ¦ ACEsampling cycles in clock-minute
¨
¨
nsampling cycles in clock -minute
©
- 10B

·
¸
¸
¹

¦ 'F

sampling cycles in clock - minute

nsampling cycles in clock -minute

The Balancing Authority’s clock-minute compliance factor (CF) becomes:

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S ta n d a rd BAL-001-0.1a — Re al P owe r Ba la n cin g Co n trol P e rfo rm a n ce

ª§ ACE ·
º
* 'Fclock -minute »
¸
Ǭ
¬©  10 B ¹ clock -minute
¼

CFclock -minute

Normally, sixty (60) clock-minute averages of the reporting Balancing Authority’s ACE and of
the respective Interconnection’s Frequency Error will be used to compute the respective hourly
average compliance parameter.

CFclock -hour

¦ CF

clock - minute

nclock -minute samples in hour

The reporting Balancing Authority shall be able to recalculate and store each of the respective
clock-hour averages (CF clock-hour average-month) as well as the respective number of
samples for each of the twenty-four (24) hours (one for each clock-hour, i.e., hour-ending (HE)
0100, HE 0200, ..., HE 2400).

¦ [(CF
¦ [n

clock - hour

)(none-minute samples in clock -hour )]

days-in - month

CFclock -hour average-month

one - minute samples in clock - hour
days-in month

¦ [(CF

clock - hour average- month

CFmonth

hours -in -day

]

)(none-minute samples in clock -hour averages )]

¦ [n

one - minute samples in clock - hour averages
hours -in day

]

The 12-month compliance factor becomes:
12

¦ (CF

month -i

CF12-month

)(none-minute samples in month i )]

i 1

12

¦ [n

( one - minute samples in month)-i

]

i 1

In order to ensure that the average ACE and Frequency Deviation calculated for any oneminute interval is representative of that one-minute interval, it is necessary that at least 50% of
both ACE and Frequency Deviation samples during that one-minute interval be present.
Should a sustained interruption in the recording of ACE or Frequency Deviation due to loss of
telemetering or computer unavailability result in a one-minute interval not containing at least
50% of samples of both ACE and Frequency Deviation, that one-minute interval shall be
excluded from the calculation of CPS1.
M2. Each Balancing Authority shall achieve, as a minimum, Requirement R2 (CPS2) compliance of
90%. CPS2 relates to a bound on the ten-minute average of ACE. A compliance percentage is
calculated as follows:

CPS 2

ª
º
Violations month
«1 
» * 100
¬ Total Periods month  Unavailable Periods month ¼

The violations per month are a count of the number of periods that ACE clock-ten-minutes
exceeded L10. ACE clock-ten-minutes is the sum of valid ACE samples within a clock-tenminute period divided by the number of valid samples.
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S ta n d a rd BAL-001-0.1a — Re al P owe r Ba la n cin g Co n trol P e rfo rm a n ce
Violation clock-ten-minutes
= 0 if

¦ ACE
nsamples in 10-minutes

d L10

= 1 if

¦ ACE

nsamples in 10-minutes

! L10

Each Balancing Authority shall report the total number of violations and unavailable periods
for the month. L10 is defined in Requirement R2.
Since CPS2 requires that ACE be averaged over a discrete time period, the same factors that
limit total periods per month will limit violations per month. The calculation of total periods
per month and violations per month, therefore, must be discussed jointly.
A condition may arise which may impact the normal calculation of total periods per month and
violations per month. This condition is a sustained interruption in the recording of ACE.
In order to ensure that the average ACE calculated for any ten-minute interval is representative
of that ten-minute interval, it is necessary that at least half the ACE data samples are present
for that interval. Should half or more of the ACE data be unavailable due to loss of
telemetering or computer unavailability, that ten-minute interval shall be omitted from the
calculation of CPS2.
D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Reliability Organization.
1.2. Compliance Monitoring Period and Reset Timeframe
One calendar month.
1.3. Data Retention
The data that supports the calculation of CPS1 and CPS2 (Appendix 1-BAL-001-0) are to
be retained in electronic form for at least a one-year period. If the CPS1 and CPS2 data
for a Balancing Authority Area are undergoing a review to address a question that has
been raised regarding the data, the data are to be saved beyond the normal retention
period until the question is formally resolved. Each Balancing Authority shall retain for a
rolling 12-month period the values of: one-minute average ACE (ACEi), one-minute
average Frequency Error, and, if using variable bias, one-minute average Frequency Bias.
1.4. Additional Compliance Information
None.

2.

Levels of Non-Compliance – CPS1
2.1. Level 1:
The Balancing Authority Area’s value of CPS1 is less than 100% but
greater than or equal to 95%.
2.2. Level 2:
The Balancing Authority Area’s value of CPS1 is less than 95% but
greater than or equal to 90%.
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S ta n d a rd BAL-001-0.1a — Re al P owe r Ba la n cin g Co n trol P e rfo rm a n ce
2.3. Level 3:
The Balancing Authority Area’s value of CPS1 is less than 90% but
greater than or equal to 85%.
2.4. Level 4:
3.

The Balancing Authority Area’s value of CPS1 is less than 85%.

Levels of Non-Compliance – CPS2
3.1. Level 1:
The Balancing Authority Area’s value of CPS2 is less than 90% but
greater than or equal to 85%.
3.2. Level 2:
The Balancing Authority Area’s value of CPS2 is less than 85% but
greater than or equal to 80%.
3.3. Level 3:
The Balancing Authority Area’s value of CPS2 is less than 80% but
greater than or equal to 75%.
3.4. Level 4:

The Balancing Authority Area’s value of CPS2 is less than 75%.

E. Regional Differences
1.

The ERCOT Control Performance Standard 2 Waiver approved November 21, 2002.

F. Associated Documents
1.

Appendix 2  Interpretation of Requirement R1 (October 23, 2007).

Version History
Version

Date

Action

Change Tracking

0

February 8, 2005

BOT Approval

New

0

April 1, 2005

Effective Implementation Date

New

0

August 8, 2005

Removed “Proposed” from Effective Date

Errata

0

July 24, 2007

Corrected R3 to reference M1 and M2
instead of R1 and R2

Errata

0a

December 19, 2007

Added Appendix 2 – Interpretation of R1
approved by BOT on October 23, 2007

Revised

0a

January 16, 2008

In Section A.2., Added “a” to end of standard Errata
number
In Section F, corrected automatic numbering
from “2” to “1” and removed “approved” and
added parenthesis to “(October 23, 2007)”

0

January 23, 2008

Reversed errata change from July 24, 2007

Errata

0.1a

October 29, 2008

Board approved errata changes; updated
version number to “0.1a”

Errata

0.1a

May 13, 2009

Approved by FERC

Page 5 of 7

S ta n d a rd BAL-001-0.1a — Re al P owe r Ba la n cin g Co n trol P e rfo rm a n ce
Appendix 1-BAL-001-0
CPS1 and CPS2 Data
CPS1 DATA

Description

Retention Requirements

H1

A constant derived from the targeted frequency
bound. This number is the same for each
Balancing Authority Area in the
Interconnection.

Retain the value of H1 used in CPS1 calculation.

ACEi

The clock-minute average of ACE.

Retain the 1-minute average values of ACE
(525,600 values).

Bi

The Frequency Bias of the Balancing Authority
Area.

Retain the value(s) of Bi used in the CPS1
calculation.

FA

The actual measured frequency.

Retain the 1-minute average frequency values
(525,600 values).

FS

Scheduled frequency for the Interconnection.

Retain the 1-minute average frequency values
(525,600 values).

CPS2 DATA

Description

Retention Requirements

V

Number of incidents per hour in which the
absolute value of ACE clock-ten-minutes is
greater than L10.

Retain the values of V used in CPS2
calculation.

H10

A constant derived from the frequency bound.
It is the same for each Balancing Authority
Area within an Interconnection.

Retain the value of H10 used in CPS2
calculation.

Bi

The Frequency Bias of the Balancing Authority
Area.

Retain the value of Bi used in the CPS2
calculation.

Bs

The sum of Frequency Bias of the Balancing
Authority Areas in the respective
Interconnection. For systems with variable
bias, this is equal to the sum of the minimum
Frequency Bias Setting.

Retain the value of Bs used in the CPS2
calculation. Retain the 1-minute minimum bias
value (525,600 values).

U

Number of unavailable ten-minute periods per
hour used in calculating CPS2.

Retain the number of 10-minute unavailable
periods used in calculating CPS2 for the
reporting period.

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S ta n d a rd BAL-001-0.1a — Re al P owe r Ba la n cin g Co n trol P e rfo rm a n ce

Appendix 2
Interpretation of Requirement 1
Request: Does the WECC Automatic Time Error Control Procedure (WATEC) violate
Requirement 1 of BAL-001-0?
Interpretation:
Requirement 1 of BAL-001 — Real Power Balancing Control Performance, is the
definition of the area control error (ACE) equation and the limits established for Control
Performance Standard 1 (CPS1).
BAL-001-0
R1. Each Balancing Authority shall operate such that, on a rolling 12-month basis, the average of
the clock-minute averages of the Balancing Authority’s Area Control Error (ACE) divided by 10B
(B is the clock-minute average of the Balancing Authority Area’s Frequency Bias) times the
corresponding clock-minute averages of the Interconnection’s Frequency Error is less than a
VSHFLILFOLPLW7KLVOLPLWİLVDFRQVWDQWGHULYHGIURPDWDUJHWHGIUHTXHQF\ERXQGVHSDUDWHO\
calculated for each Interconnection) that is reviewed and set as necessary by the NERC
Operating Committee.

ƒ

The WATEC procedural documents ask Balancing Authorities to maintain raw ACE for CPS
reporting and to control via WATEC-adjusted ACE.

ƒ

As long as Balancing Authorities use raw (unadjusted for WATEC) ACE for CPS reporting
purposes, the use of WATEC for control is not in violation of BAL-001 Requirement 1.

Page 7 of 7

BAL-0 0 1 -1 – Re a l P o w e r
Ba la n cin g Co n t r o l
P e r fo r m a n ce St a n d a r d
Ba ck g ro u n d Do cu m e n t
January 2012

3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Table of Contents

Table of Contents
Table of Contents ............................................................................................................................ 2
Introduction .................................................................................................................................... 3
Background and Rationale by Requirement ................................................................................... 4
Requirement 1 ............................................................................................................................ 4
Requirement 2 ............................................................................................................................ 5

BAL-001-1 - Background Document
June 4, 2012

2

Real Power Balancing Control Performance Standard Background Document

Introduction
This document provides background on the development, testing, and implementation of BAL001-1 - Real Power Balancing Control Standard. The intent is to explain the rationale and
considerations for the requirements and their associated compliance information.
The original work for this standard was done by the Balancing Authority Controls standard
drafting team, which later joined with the Reliability-based Control Standard drafting team.
These combined teams were renamed Balance Authority Reliability-based Control standard
drafting team (BARC SDT).
The purpose of proposed Standard BAL-001-1 is to maintain Interconnection frequency within
predefined frequency limits. This draft standard defines Balancing Authority ACE Limit (BAAL),
and required the Balancing Authority (BA) to balance its resources and demand in Real-time so
that its clock-minute average of its Area Control Error (ACE) does not exceed its BAAL for more
than 30 consecutive clock-minutes.
As a proof of concept for the proposed BAAL standard, a BAAL field trial was approved by the
NERC Standards Committee and the Operating Committee. Currently participating in the field
trial are 13 Balancing Authorities in the Eastern Interconnection, 26 Balancing Authorities in the
Western Interconnection, the ERCOT Balancing Authority, and Quebec. Reliability Coordinators
for all Interconnections continue to monitor the performance of those participating Balancing
Authorities and provide information to support monthly analysis of the BAAL field trial. As of
the end of September 2011, no reliability issues with the BAAL field trial have been identified by
any Reliability Coordinator.
Historical Significance
A1-A2 Control Performance Policy was implemented in 1973 as:
x
x
x

A1 required the Balancing Authority’s ACE to return to zero within 10 minutes of previous
zero.
A2 required that the Balancing Authority’s averaged ACE for each 10-minute period must be
within limits.
A1-A2 had three main short comings:
ƒ Lack of theoretical justification
ƒ Large ACE treated the same as a small ACE, regardless of direction
ƒ Independent of Interconnection frequency

In 1996, a new NERC policy was approved which used CPS1, CPS2, and DCS.
CPS1is a:
x
x

Statistical measure of ACE variability
Measure of ACE in combination with the Interconnection’s frequency error

BAL-001-1 - Background Document
June 4, 2012

3

Real Power Balancing Control Performance Standard Background Document
x

Based on an equation derived from frequency-based statistical theory
CPS2 is:
x
x

Designed to limit a Control Area’s (now known as a Balancing Authority)
unscheduled power flows
Similar to the old A2 criteria

The proposed BAL-001-1 retains CPS1, but proposes a new measure BAAL. Currently CPS2:
x Does not have a frequency component.
x CPS2 many times give the Balancing Authority the indication to move their ACE opposite
to what will help frequency.
x Requires Balancing Authorities to comply 90 percent of the time as a minimum.

Background and Rationale by Requirement
Requirement 1
R1. Each Balancing Authority shall operate such that the Balancing Authority’s Control
Performance Standard 1 (CPS1) (as calculated in Attachment 1) is greater than or equal
to 100 percent for the applicable Interconnection in which it operates for each 12month period, evaluated monthly, to support Interconnection frequency.
Background and Rationale
Requirement R1 is not a new requirement. It is a restatement of the current BAL-001-0.1a
Requirement R1 with its equation and explanation of its individual components moved to an
attachment, Attachment 1 - Equations Supporting Requirement R1 and Measure M1. This
requirement is commonly referred to as Compliance Performance Standard 1 (CPS1). R1 is
intended to measure how well a Balancing Authority is able to control its generation and load
management programs, as measured by its Area Control Error (ACE), to support its
Interconnection’s frequency over a rolling one-year period.
CPS1 is a measure of a Balancing Authority’s control performance as it relates to its generation,
Load management, and Interconnection frequency when measured in one-minute averages
over a rolling one-year period. If all Balancing Authorities on an Interconnection are compliant
with the CPS1 measure, then the Interconnection will have a root mean square (RMS)
frequency error less than the Interconnection’s Epsilon 1.
A Balancing Authority reports its CPS1 value to its regional entity each month. This monthly
value provides trending data to the Balancing Authority, NERC resources subcommittee, and
others as needed to detect changes that may indicate poor control on behalf of the Balancing
BAL-001-1 - Background Document
June 4, 2012

4

Real Power Balancing Control Performance Standard Background Document
Authority. Requirement R1 remains unchanged, although the wording of the requirement was
modified to provide clarity.
Requirement 2
R2. Each Balancing Authority shall operate such that its clock-minute average of reporting
ACE does not exceed for more than 30 consecutive clock-minutes its clock-minute
Balancing Authority ACE Limit (BAAL) (as calculated in Attachment 2) for the applicable
Interconnection in which it operates to support Interconnection frequency.
Background and Rationale
Requirement R2 is a new requirement intended to replace existing BAL-001-0.1a Requirement
R2, commonly referred to as Control Performance 2 (CPS2). The proposed Requirement R2 is
intended to enhance the reliability of each Interconnection by maintaining frequency within
predefined limits under all conditions.
The Balancing Authority ACE Limits (BAAL) are unique for each Balancing Authority and provide
dynamic limits for its Area Control Error (ACE) value limit as a function of its Interconnection
frequency. BAAL was derived based on reliability studies and analysis which defined a
Frequency Trigger Limit (FTL) bound measured in Hz. The FTL is equal to 60 Hz, plus or minus
three times an Interconnection’s Epsilon 1 value. Epsilon 1 is the root mean square (RMS)
targeted frequency error for each Interconnection, as recommended by the NERC Resources
Subcommittee and approved by the NERC Operating Committee. Epsilon 1 values for each
Interconnection are unique. When a Balancing Authority exceeds its BAAL, it is providing more
than its share of risk that the Interconnection will exceed its FTL. When all Balancing
Authorities are within their BAAL (high and low), the Interconnection frequency will be within
its FTL limits.
BAAL is defined by two equations; BAAL low and BAAL high. BAAL low is for Interconnection
frequency values less than 60 Hz, and BAAL high is for Interconnection frequency values greater
than 60 Hz. BAAL values for each Balancing Authority are dynamic and change as
Interconnection frequency changes. For example, as Interconnection frequency moves from 60
Hz, the ACE limit for each Balancing Authority becomes more restrictive. The BAAL provides
each Balancing Authority a dynamic ACE limit that is a function of Interconnection frequency.
CPS2 was not designed to address Interconnection frequency. Currently, it measures the ability
of a Balancing Authority to maintain its average ACE within a fixed limit of plus or minus a MW
value called L10. To be compliant, a Balancing Authority must demonstrate its average ACE
value during a consecutive 10-minute period was within the L10 bound 90 percent of all 10minute periods over a one-month period. While this standard does require the Balancing
BAL-001-1 - Background Document
June 4, 2012

5

Real Power Balancing Control Performance Standard Background Document
Authority to correct its ACE to not exceed specific bounds, it fails to recognize Interconnection
frequency. For example, the Balancing Authority may be increasing or decreasing generation to
meet its CPS2 bounds, even if this is a direction that reduces reliability by moving
Interconnection frequency farther from its scheduled value. CPS2 allows a Balancing Authority
to be outside its ACE bounds 10 percent of the time. There are 72 hours per month that a
Balancing Authority’s ACE can be outside its L10 limits and be compliant with CPS2.
In summary, the proposed BAAL requirement will provide dynamic limits that are Balancing
Authority and Interconnection specific. These ACE values are based on identified
Interconnection frequency limits to ensure the Interconnection returns to a reliable state when
an individual Balancing Authority’s ACE or Interconnection frequency deviates into a region that
contributes too much risk to the Interconnection. This requirement replaces and improves
upon CPS2, which is not dynamic, is not based on Interconnection frequency, and allows
significant hours when a Balancing Authority’s ACE values are unbounded.

BAL-001-1 - Background Document
June 4, 2012

6

Implementation Plan

Project 2010-14.1 Balancing Authority Reliability-based Controls
- Reserves
Implementation Plan for BAL-001-1 – Real Power Balancing Control Performance
Approvals Required
BAL-001-1 – Real Power Balancing Control Performance
Prerequisite Approvals
None
Revisions to Glossary Terms
The following definitions shall become effective when BAL-001-1 becomes effective:
Balancing Authority ACE Limit (BAAL): The limit beyond which a Balancing Authority
contributes more than its share of Interconnection frequency control reliability risk. This
definition applies to a high limit (BAAL High ) and a low limit (BAAL Low ).
Reporting ACE: The scan rate values of a Balancing Authority’s Area Control Error (ACE)
measured in MW, as defined in BAL-001, which includes the difference between the Balancing
Authority’s actual Interchange and its scheduled Interchange, plus its Frequency Bias obligation,
plus any known meter error.
Interconnection: When capitalized, any one of the four major electric system networks in North
America: Eastern, Western, Texas and Quebec.
The existing definition of Interconnection should be retired at midnight of the day immediately prior to
the effective date of BAL-001-1, in the jurisdiction in which the new standard is becoming effective.
The proposed revised definition for “Interconnection” is incorporated in the NERC approved standards,
detailed in Attachment 1 of this document.

Applicable Entities
Balancing Authority
Applicable Facilities
N/A
Conforming Changes to Other Standards
None
Effective Dates
BAL-001-1 shall become effective as follows:
First day of the first calendar quarter that is six months beyond the date that this standard is
approved by applicable regulatory authorities, or in those jurisdictions where regulatory
approval is not required, the standard becomes effective the first day of the first calendar
quarter that is six months beyond the date this standard is approved by the NERC Board of
Trustees, or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities.
Justification
The six-month period for implementation of BAL-001-1 will provide ample time for Balancing
Authorities to make necessary modifications to existing software programs to perform the BAAL
calculations for compliance.
Retirements
BAL-001-0.1a – Real Power Balancing Control Performance should be retired at midnight of the day
immediately prior to the effective date of BAL-001-1 in the particular jurisdiction in which the new
standard is becoming effective.

BAL-001-1 – Real Power Balancing Control Performance
June 4, 2012

2

Attachment 1
Approved Standards Incorporating the Term “Interconnection”
BAL-001-0.1a — Real Power Balancing Control Performance
BAL-002-0 — Disturbance Control Performance
BAL-002-1 — Disturbance Control Performance
BAL-003-0.1b — Frequency Response and Bias
BAL-004-0 — Time Error Correction
BAL-004-1 — Time Error Correction
BAL-004-WECC-01 — Automatic Time Error Correction
BAL-005-0.1b — Automatic Generation Control
BAL-006-2 — Inadvertent Interchange
WECC Standard BAL-STD-002-1 - Operating Reserves
CIP-001-1a — Sabotage Reporting
CIP-001-2a— Sabotage Reporting
CIP–002–4 — Cyber Security — Critic a l Cyber Asset Identification
CIP–005–3a — Cyber Security — Electronic Security Perimeter(s )
COM-001-1.1 — Telecommunications
EOP-001-2b — Emergency Operations Planning
EOP-002-2.1 — Capacity and Energy Emergencies
EOP-002-3 — Capacity and Energy Emergencies
EOP-003-1 — Load Shedding Plans
EOP-003-2— Load Shedding Plans
EOP-004-1 — Disturbance Reporting
EOP-005-1 — System Restoration Plans
EOP-005-2 — System Restoration from Blacks tart Resources
EOP-006-1 — Reliability Coordination — System Restoration
EOP-006-2 — System Restoration Coordination
FAC-008-3 — Facility Ratings
FAC-010-2 — System Operating Limits Methodology for the Planning Horizon
FAC-011-2 — System Operating Limits Methodology for the Operations Horizon
INT-005-3 — Interchange Authority Distributes Arranged Interchange
INT-006-3 — Response to Interchange Authority
INT-008-3 — Interchange Authority Distributes Status
IRO-001-1.1 — Reliability Coordination — Responsibilities and Authorities
IRO-001-2 — Re liability Coordination — Responsibilities and Authorities
IRO-002-1 — Reliability Coordination — Facilities
IRO-002-2 — Reliability Coordination — Facilities
IRO-004-1 — Reliability Coordination — Operations Planning

BAL-001-1 – Real Power Balancing Control Performance
June 4, 2012

3

IRO-005-2a — Reliability Coordination — Current Day Operations
IRO-005-3a — Reliability Coordination — Current Day Operations
IRO-006-5 — Reliability Coordination — Transmission Loading Relief
IRO-006-EAST-1 — TLR Procedure for the Eastern Interconnection
IRO-014-1 — Procedures, Processes, or Plans to Support Coordination Between
Reliability Coordinators
IRO-014-2 — Coordination Among Reliability Coordinators
IRO-015-1 — Notifications and Information Exchange Between Reliability Coordinators
IRO-016-1 — Coordination of Real-time Activities Between Reliability Coordinators
MOD-010-0 — Steady-State Data for Transmission System Modeling and Simulation
MOD-011-0 — Regional Steady-State Data Requirements and Reporting Procedures
MOD-012-0 — Dynamics Data for Transmission System Modeling and Simulation
MOD-013-1 — RRO Dynamics Data Requirements and Reporting Procedures
MOD-014-0 — Development of Interconnection-Specific Steady State System Models
MOD-015-0 — Development of Interconnection-Specific Dynamics System Models
MOD-015-0.1 — Development of Interconnection-Specific Dynamics System
Models
MOD-030-02 — Flowgate Methodology
PRC-001-1 — System Protection Coordination
PRC-006-1 — Automatic Underfrequency Load Shedding
TOP-002-2a — Normal Operations Planning
TOP-004-2 — Transmission Operations
TOP-005-1.1a — Operational Reliability Information
TOP-005-2a — Operational Reliability Information
TOP-008-1 — Response to Transmission Limit Violations
VAR-001-1 — Voltage and Reactive Control
VAR-001-2 — Voltage and Reactive Control
VAR-002-1.1b — Generator Operation for Maintaining Network Voltage Schedules

BAL-001-1 – Real Power Balancing Control Performance
June 4, 2012

4

BAL-001-0.1a Mapping to Proposed NERC Reliability Standard BAL-001-1
Standard BAL-001-0.1a
Comment
Proposed Standard BAL-001-1
NERC Board Approved
R1. Each Balancing Authority shall
This Requirement has been
Requirement R1
operate such that, on a rolling 12moved into BAL-001-1
Each Balancing Authority shall operate such that the
month basis, the average of the
Requirement R1
Balancing Authority’s Control Performance Standard 1 (CPS1),
clock-minute averages of the
as calculated in Attachment 1, is greater than or equal to
Balancing Authority’s Area Control
100% for the applicable Interconnection in which it operates
Error (ACE) divided by 10B (B is the
for each 12 month period, evaluated monthly, to support
clock-minute average of the
interconnection frequency.
Balancing Authority Area’s
Frequency Bias) times the
corresponding clock-minute
The calculation equation for CPS1 has been moved to Attachment
averages of the Interconnection’s
1 of BAL-001-1.
Frequency Error is less than a
ƐƉĞĐŝĨŝĐůŝŵŝƚ͘dŚŝƐůŝŵŝƚɸ12 is a
constant derived from a targeted
frequency bound (separately
calculated for each

Project 2010-14.1 Balancing Authority Reliability-based
Controls - Reserves
BAL-001-1 Real Power Balancing Control Performance
Mapping Document

BAL-001-1 Real Power Balancing Control Performance
June 4, 2012

The equation for ACE is:
ACE = (NIA - NIS) - 10B (FA - FS) - IME
where:
x NIA is the algebraic sum of
actual flows on all tie lines.
x NIS is the algebraic sum of
scheduled flows on all tie
lines.
x B is the Frequency Bias
Setting (MW/0.1 Hz) for the
Balancing Authority. The
constant factor 10 converts
the frequency setting to
MW/Hz.
x FA is the actual frequency.
x FS is the scheduled
frequency. FS is normally 60

BAL-001-0.1a Mapping to Proposed NERC Reliability Standard BAL-001-1
Standard BAL-001-0.1a
Comment
Proposed Standard BAL-001-1
NERC Board Approved
Interconnection) that is reviewed
and set as necessary by the NERC
Operating Committee.
AVGPeriod
-10B

2

BAL-001-1 Real Power Balancing Control Performance
June 4, 2012

3

BAL-001-0.1a Mapping to Proposed NERC Reliability Standard BAL-001-1
Standard BAL-001-0.1a
Comment
Proposed Standard BAL-001-1
NERC Board Approved
Hz but may be offset to
effect manual time error
corrections.
x IME is the meter error
correction factor typically
estimated from the
difference between the
integrated hourly average
of the net tie line flows
(NIA) and the hourly net
interchange demand
measurement (megawatthour). This term should
normally be very small or
zero.
R2. Each Balancing Authority shall
Requirement R2
This Requirement has been
operate such that its average ACE
removed from BAL-001-1 and
Each Balancing Authority shall operate such that its clockfor at least 90% of clock-tenreplaced with the proposed
minute average of Reporting ACE does not exceed for
minute periods (6 non-overlapping Requirement R2 for BAAL.
more than 30 consecutive clock-minutes its clock-minute
periods per hour) during a calendar
Balancing Authority ACE Limit (BAAL), as calculated in
month is within a specific limit,
Attachment 2, for the applicable Interconnection in which
referred to as L10.
it operates to support interconnection frequency.
AVG10-minute (ACEi ) чL10
where:

BAL-001-1 Real Power Balancing Control Performance
June 4, 2012

R3. Each Balancing Authority providing
Overlap Regulation Service shall

This Requirement has been
moved into the BAL-001-1

4

Applicability Section 4.1.1 and Attachment 1
A Balancing Authority providing Overlap Regulation Service

BAL-001-0.1a Mapping to Proposed NERC Reliability Standard BAL-001-1
Standard BAL-001-0.1a
Comment
Proposed Standard BAL-001-1
NERC Board Approved
The calculation equation for BAAL is located in Attachment 2 of
L10сϭ͘ϲϱ˒10
BAL-001-1.
ɸ10 is a constant derived from the
targeted frequency bound. It
is the targeted root-meansquare (RMS) value of tenminute average Frequency
Error based on frequency
performance over a given
LJĞĂƌ͘dŚĞďŽƵŶĚ͕ɸ10, is the
same for every Balancing
Authority Area within an
Interconnection, and Bs is the
sum of the Frequency Bias
Settings of the Balancing
Authority Areas in the
respective Interconnection.
For Balancing Authority Areas
with variable bias, this is
equal to the sum of the
minimum Frequency Bias
Settings.

Any Balancing Authority receiving
Overlap Regulation Service shall
not have its control performance
evaluated (i.e. from a control
performance perspective, the
Balancing Authority has shifted all
control requirements to the
Balancing Authority providing
Overlap Regulation Service).

BAL-001-1 Real Power Balancing Control Performance
June 4, 2012

R4.

This Requirement has been
moved into the BAL-001-1
Applicability Section and
Attachment 1.

5

Applicability Section 4.1.3 and Attachment 1
A Balancing Authority receiving Overlap Regulation Service is
not subject to CPS1 or BAAL compliance evaluation.

BAL-001-0.1a Mapping to Proposed NERC Reliability Standard BAL-001-1
Standard BAL-001-0.1a
Comment
Proposed Standard BAL-001-1
NERC Board Approved
evaluate Requirement R1 (i.e.,
Applicability Section and
to another Balancing Authority calculates its CPS1
Control Performance Standard 1 or Attachment 1.
performance after combining its Reporting ACE and
CPS1) and Requirement R2 (i.e.,
Frequency Bias Settings with the Reporting ACE and
Control Performance Standard 2 or
Frequency Bias Settings of the Balancing Authority receiving
CPS2) using the characteristics of
Regulation Service.
the combined ACE and combined
Frequency Bias Settings.

Violation Risk Factor and Violation Severity
Level Assignments

Project 2010-14.1 Balancing Authority Reliability-based Controls
- Reserves
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-001-1, Real Power Balancing Control
Performance. 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-001-1 Real Power Balancing Control Performance
VRF and VSL Assignments – December, 2011

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
x
x
x
x
x
x
x
x
x
x
x
x

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-001-1 Real Power Balancing Control Performance
VRF and VSL Assignments – December, 2011

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-001-1:

There are two requirements in BAL-001-1. Both requirements were assigned a “Medium” VRF.
VRF for BAL-001-1, Requirement R1:

ͻ

FERC Guideline 2 — Consistency within a reliability standard exists. The requirement does not
contain sub-requirements. Both requirements in BAL-003-1 are assigned a “Medium” VRF.
Requirement R1 is similar in scope to Requirement R2.

ͻ

FERC Guideline 3 — Consistency among reliability standards exists. This requirement is similar
in concept to the current enforceable BAL-001-0.1a Standard Requirements R1 and R2, which
have an approved Medium VRF.

ͻ

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
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.

ͻ

FERC Guideline 5 — This requirement does not co-mingle reliability objectives.

BAL-001-1 Real Power Balancing Control Performance
VRF and VSL Assignments – December, 2011

3

VRF for BAL-001-1, Requirement R2:

ͻ

FERC Guideline 2 — Consistency within a reliability standard exists. The requirement does not
contain subrequirements. Both requirements in BAL-003-1 are assigned a “Medium” VRF.
Requirement R2 is similar in scope to Requirement R1.

ͻ

FERC Guideline 3 — Consistency among Reliability Standards exists. This requirement is similar
in concept to the current enforceable BAL-001-0.1a standard Requirements R1 and R2, which
have an approved Medium VRF.

ͻ

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
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.

ͻ

FERC Guideline 5 — This requirement does not co-mingle reliability objectives.

BAL-001-1 Real Power Balancing Control Performance
VRF and VSL Assignments – December, 2011

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

High

Severe

Missing a minor
element (or a small
percentage) of the
required performance.
The performance or
product measured has
significant value, as it
almost meets the full
intent of the
requirement.

Missing at least one
significant element (or
a moderate
percentage) of the
required performance.
The performance or
product measured still
has significant value in
meeting the intent of
the requirement.

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-001-1 meet the FERC Guidelines for assessing VSLs:

BAL-001-1 Real Power Balancing Control Performance
VRF and VSL Assignments – December, 2011

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 perviolation-per-day basis is the “default” for penalty calculations.

BAL-001-1 Real Power Balancing Control Performance
VRF and VSL Assignments – December, 2011

6

The NERC VSL
Guidelines are
satisfied by
incorporating
percentage of
noncompliance
performance for
the calculated
CPS1.

As drafted, the
proposed VSLs do not
lower the current level
of compliance.

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

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 percentage of
intervals the entity is
noncompliant.

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

BAL-001-1 Real Power Balancing Control Performance
VRF and VSL Assignments – December, 2011

R1

R#

Compliance with
NERC VSL
Guidelines

V SLs for BAL-001-1 Requirem ent R1:

Proposed VSLs do not
expand on what is
required in the
requirement. The VSLs
assigned only consider
results of the calculation
required. Proposed VSLs
are consistent with the
requirement.

Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement

Guideline 3

7

Proposed VSLs are
based on single
violations and not a
cumulative violation
methodology.

Violation Severity Level
Assignment Should Be
Based on A Single
Violation, Not on A
Cumulative Number of
Violations

Guideline 4

The NERC VSL
Guidelines are
satisfied by
incorporating
percentage of
noncompliance
performance
for the
calculated
BAAL.

This is a new requirement.
As drafted, the proposed
VSLs do not lower the
current level of compliance.

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

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
percentage of time the
entity is noncompliant.

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

BAL-001-1 Real Power Balancing Control Performance
VRF and VSL Assignments – December, 2011

R2.

R#

Compliance with
NERC VSL
Guidelines

V SLs for BAL-001-1 Requirem ent R2:

Proposed VSLs do not
expand on what is
required in the
requirement. The VSLs
assigned only consider
results of the calculation
required. Proposed VSLs
are consistent with the
requirement.

Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement

Guideline 3

8

Proposed VSLs are
based on single
violations and not a
cumulative
violation
methodology.

Violation Severity
Level Assignment
Should Be Based on
A Single Violation,
Not on A Cumulative
Number of Violations

Guideline 4

Standards Announcement

Project 2010-14.1 Phase 1 of Balancing Authority Reliability-based
Controls: Reserves
Formal Comment Period Open: June 4 – July 3, 2012
Now Available
Formal comment periods are open for the following four standards: BAL-001-1 - Real Power Balancing Control
Performance, BAL-002-2 - Contingency Reserve for Recovery from a Balancing Contingency Event, BAL-012-1 Operating Reserve Planning, and BAL-013-1 - Large Loss of Load Performance through 8 p.m. Tuesday, July 3,
2012.
Instructions for Commenting
Formal comment periods are open through 8 p.m. Eastern on Tuesday, July 3, 2012.
Please use following comment forms to submit comments:
Comment Form – BAL-001-1
Comment Form – BAL-002-2
Comment Form – BAL-012-1
Comment Form – BAL-013-1
Due to the length of the definitions and the formatting limitations of the electronic commenting software,
please refer to the Unofficial Comment Form in Word on the project page for redlines referenced in Question
Two for BAL-001-1 in the electronic comment form.
If you experience any difficulties in using the electronic forms, please contact Monica Benson at
[email protected]. An off-line, unofficial copy of each of the comment forms is posted on the project
page.
Next Steps
The drafting team will consider all comments and determine whether to make changes to the standards and
associated documents. After the standards and associated documents are revised, the drafting team will submit
its work for quality review prior to the next posting.
Background
The NERC Standards Committee approved the merger of Project 2007-05 Balancing Authority Controls and
Project 2007-18 Reliability-based Control as Project 2010-14 Balancing Authority Reliability-based Controls on
July 28, 2010. The NERC Standards Committee also approved the separation of Project 2010-14 Balancing
Authority Reliability-based Controls into two phases and moving Phase 1 (Project 2010-14.1 Balancing Authority
Reliability-based Controls – Reserves) into formal standards development on July 13, 2011. The Standard

Drafting Team has revised BAL-001-0.1a Real Power Balancing Control Performance and BAL-002-1 Disturbance
Control Performance. The Standard Drafting Team proposes to eliminate the CPS2 metric in the present BAL001-01a standard and replace it with a new Balancing Authority ACE limits metric. The Standard Drafting Team
has completely revised the current BAL-002-1 standard to eliminate the ambiguity and move requirements from
the “Additional Compliance Information” section into the requirements section. The Standard Drafting Team is
also proposing two new standards BAL-012-1 Operating Reserve Planning, and BAL-013-1 Large Loss of Load
Performance to address planning for Regulating, Contingency and Frequency Responsive Reserves and
responding to a Large Loss of Load event.
The four standards within Project 2010-14.1 are an important part of the ERO’s strategic goal to develop
technically sufficient standards with requirements that provide clear and unambiguous performance
expectations and reliability benefits.
Standards Development Process
The Standards Processes Manual contains all the procedures governing the standards development process.
The success of the NERC standards development process depends on stakeholder participation. We extend out
thanks to all those who participate.

For more information or assistance, please contact Monica Benson,
Standards Process 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

Announcement – Initial Posting of Phase 1 of Balancing Authority Reliability-based Controls: Reserves

2

Name (22 Responses)
Organization (22 Responses)
Group Name (14 Responses)
Lead Contact (14 Responses)
Question 1 (32 Responses)
Question 1 Comments (36 Responses)
Question 2 (31 Responses)
Question 2 Comments (36 Responses)
Question 3 (31 Responses)
Question 3 Comments (36 Responses)
Question 4 (30 Responses)
Question 4 Comments (36 Responses)
Question 5 (33 Responses)
Question 5 Comments (36 Responses)
Question 6 (27 Responses)
Question 6 Comments (36 Responses)
Question 7 (28 Responses)
Question 7 Comments (36 Responses)
Question 8 (27 Responses)
Question 8 Comments (36 Responses)
Question 9 (30 Responses)
Question 9 Comments (36 Responses)
Question 10 (0 Responses)
Question 10 Comments (36 Responses)
Question 11 (0 Responses)
Question 11 Comments (36 Responses)

Group
LG&E and KU Services
Brent ingebrigtson
Yes
LG&E and KU Services suggest removing “reliability risk” from the end of the first sentence in the
BAAL definition
No
The posted BAL-001-1 shows the Purpose Statement as: Purpose: To control Interconnection
frequency within defined limits. The purpose statement in the draft standard is preferred over the
Purpose Statement as shown in Question 3.
Yes
LGE and KU Services is a participant in the BAAL Field Test and support the implementation of the
BAAL standard.

LG&E and KU Services suggests that the SDT clarifies that the standard will not require monthly
reporting as if currently performed by the BA (CPS1 and BAAL) to SERC/NERC/FERC but that the BA
will need to evaluate CPS1 monthly and BAAL continuously.
Individual
Robert Blohm
Keen Resources Asia Ltd.

Yes
Yes
Yes
Delete "in support of interconnection frequency". It's redundant, and childishly repetitive of the same
term. You don't control something to within limits in order to undermine (= not support) those limits!
Yes
Yes
Yes
Yes
Yes
No
No. In particular this sentence on page 5 of the background document provides no technical
justification for the the "3" in the plus/minus 3epsilon FTL: "BAAL was derived based on reliability
studies and analysis which defined a Frequency Trigger Limit (FTL) bound measured in Hz." The
analysis commissioned by NERC without tender to an outside software vendor was demolished in the
extensive posted comments by 2 statistical experts, California ISO and NPCC. The analysis was
junked together with the rejected proposed standard as NERC proceeded to form a new drafting team
to rebuild the standard. 3 has been demonstrated throughout the field test to be too tight in terms of
generating too many BAAL exceedences to be addressed immediately by the BA. The BA needs to
wait at least 5 minutes for enough of these exceedences to go away to leave a feasible/manageable
number begin to addressing. Such waiting jeopardizes reliability. It is much more prudent to raise the
"3" to somewhere between 4 or 5 to generate exceedences small enough in number to be
feasible/manageable to begin addressing immediately upon occurrence. Setting the FTL at a high
enough threshold where the number of exceedences becomes feasible or manageable enough to be
addressed immediately upon occurrence instead of 5 or more minutes after they have begun if FTL is
set at too low a multiple of epsilon, is least expensive and most favorable to reliability. The field test
has not "proved" that 3 is the proper multiple just because there has been no blackout. Otherwise we
can go home until the next blackout. Instead the field test has produced the data supporting the
contention that the limit is too tight for reliability because it generates too many short-lived
exceedences and thereby encourages waiting to address the exceedences that will persist and be very
serious. After the demise of the previous proposed standard, NERC elected to change policy and stop
commissioning research and therefore development of any thorough technical justification for the
present proposed standard. In other words, NERC can no longer justify a reliability standard by any
documented scientific procedure of its own.
The technically unjustified tight multiple of "3" epsilon (versus between 4 and 5) in the Frequency
Trigger Limit (FTL) on page 10 (Attachment 2) of the Standard violates (1) the requirement that
reliability standards not interfere with the "just and reasonable" economic basis for market efficiency
and (2) the requirement that reliability standards improve not reduce reliability. Point (2) is covered
in my comments to Question 9. The multiple of 3 raises reliability cost not just unnecessarily, but
perversely in exchange for less reliability. That interferes with the normal "just and reasonable"
cost/price basis for markets that must allow for costs of necessary reliability provided those costs are
allocated in a way that is just and reasonable and not perverse to reliability. It is well-known that, by
Bayesian "multiplication" of "conditional" probability, the probability of being at the FTL is "multiplied
by" (not "added to") the "conditional" probability of the system's having a once-in-ten-years event
provided it is at the FTL, and is an infinitesimal fraction of the probability of the system's reaching a
once-in-ten-years event. Probabilities are fractions of 1. A fraction times a fraction is an infinitesimal.
Contrary to the transmission/congestion engineer's deterministic practice of "adding" transmission

capacities/contingencies, contingent/conditional probabilities are multiplied, not added. Transmission
management/planning practices are not applicable to generation/load frequency control. Accordingly
the FTL, regardless of whether the multiple of epsilon is 3, 4 or 5, is already in the realm one-event-in
hundreds, thousands of years. So, there is no issue that a higher ("5") or lower ("3") multiple of
epsilon is in a "dangerous" zone of unreliability. The issue is more of how "unnecessarily" tight the
limit is in terms of adding to the cost of operations that participants then seek to avoid by ignoring
the limit for the initial five or more minutes of a BAAL exceedence and thereby more than undo the
supposed reliability benefit of the tightness!
Group
ISO's Standards Review Committee
Terry Bilke
No
The definition of reporting ACE is nearly identical to the current definition of ACE, but the appendix
adds complexity. There should be no need for this new definition. The description of the definition in
the attachment is overly prescriptive. It has a redundant and more restrictive requirement for
frequency resolution than BAL-005. It also created a new term, Net Metering Error that is more
prescriptive than how metering error is corrected for today.
No
While we agree that these four entities comprise the four major Interconnections, the term is used
scores of times in other standards. It is beyond the scope of this drafting team to redefine
expectations of other standards.
Yes
Yes
1)While we agree that the 12 month rolling average performance is evaluated monthly, that does not
mean that substandard performance in one month should result in many months of repeat violations
until that bad month rolls out the average. Non-compliance should only accrue if the BA is not under a
mitigation plan and has new months of non-compliant performance. 2)The purpose of averaging is to
account for both the good and bad performances experienced over the 12 months in question. We
suggest that the SDT develop a criterion that identifies a given month performance as being out of
limits and that the performance is so good or so bad that the monthly value either be dropped from
the averaging or it be substituted with the limiting value.
Yes
Yes
Yes
Yes
The drafting team may want to look at how small BAs are impacted by R2. The CPS curve for small
BAs has a wider tail. The performance expectations may not be the same.
No
1) If the background document is expected to be used just to explain the team’s work, we have no
issue with it. If it is expected to replace the current Performance Standards Reference Guidelines in
the NERC Operating Manual, the document lacks significant detail. 2) While it is not material to the
new standard, the A1 criteria is not properly stated. Under A1, ACE needed to cross zero at least once
in every ten minute period of the hour and that the total non-crossings had to be less than 10 percent
of all periods.
1)The concept of a definition is to provide a generic baseline that allows other descriptive items to be
identified. For example: An Interconnection could be defined as a collection of loads, suppliers and
transmission that operates synchronously. The Eastern Interconnection would be understood to be

that group of … 2)BAAL should be incorporated within a requirement as a performance level. It should
not be a definition. 3)Similarly with ACE. ACE is defined as S-A + B delta f. The scan rate details are
subsets of that definition; they are not the definition. 4)The applicable entities should not be defined
by the methodology they use to meet the standard, nor should requirements be placed in the
Applicable entity definition. 5)Sections 4.1.1 and 4.1.2 are unclear as to which entities are subject to
complying with the standard. Further, the word “calculates” in both Sections turn these Sections into
requirements rather than specifying the entities being responsible for meeting Requirements R1 and
R2. 6)Inferring from Section 4.1.3, we interpret these Sections to mean that the “Balancing Authority
that provides Overlap Regulation Service to another Balancing Authority”. In that case, a requirement
to hold the service providing BAs responsible for calculating its CPS1 performance after combining its
Reporting ACE and Frequency Bias Settings with the Reporting ACE, and Frequency Bias Settings of
the Balancing Authority receiving the Regulation Service, would be necessary. Same applies to the
BAAL calculation implied in Section 4.1.3
Individual
Mike Goodenough
pwx
Yes
Yes
No
No, the Purpose Statement is inadequate. The purpose of the standard should be to control BAA ACE
within defined limits in support of Interconnection Frequency, and to prevent BAA ACE from having a
detrimental impact to other entities on the grid. In Order No. 890, the Federal Energy Regulatory
Commission (FERC or the Commission) recognized the potential for inadvertent energy flows between
adjacent BAs to both jeopardize reliability and to cause undue harm to customers on the grid. Such
inadvertent energy flows are driven by the size of each BAAs ACE, as primarily contained by CPS2
under the current BAL-001, and the new proposed BAL-001 standard. Powerex believes that the
development of the BAL-001 standard based on the current purpose statement will allow entities to
create deliberate inadvertent flows within the standards boundaries, without regard to the impact to
transmission customers on the grid. This may result in substantial curtailments to transmission
customers in direct contravention of the Commission’s open access transmission principles.
Yes
No
No. The standard is inadequate. The requirement will allow BA’s to operate in a way that could
significantly increase risk to the interconnection, for up to 30 minutes, without penalty. Worse, it will
allow BA’s to “sawtooth”: operate outside the BAAL limit for extended periods of time (up to 30
minutes), change operations for as little as one minute to bring their ACE back into the BAAL limit to
reset the 30 minute clock, and then again start operating outside the BAAL limit, and do so cyclically,
for extended periods. This behavior was exhibited to some extent by several BAsduring the field trial,
so there should be every expectation that this type of behavior will continue, if not spread and
worsen, if this new standard was put in place. In the Background Document for the standard the
drafting team pointed out that CPS2 “… allows significant hours when a Balancing Authority’s ACE
values are unbounded.” Because R2 of the proposed standard will allow BAs to cyclically operate
outside the BAAL limit as described above, the problem of BA’s operating with an unbounded ACE
could actually become worse under the proposed standard, not better. Powerex notes that no
technical justification has been put forward as to why a BAA should be able to operate outside the
BAAL limit for 30 minutes. We recommend that the drafting team consider a shorter period (e.g. 5
minutes). As well, to prevent the sawtoothing behavior, Powerex recommends that a monthly
maximum be set on the number of times a BAA can exceed the BAAL limit (e.g. 5 times per month).
Another concern is that the requirement will allow unlimited unscheduled flow, across interties when
the actual system frequency is close to the scheduled frequency. There seems to be a disregard for
the fact that unscheduled flows can have a significant detrimental impact on scheduled flows.
Curtailments to scheduled flows is one of the main tools used to keep the system operating within

limits during period of high unscheduled flows, effectively giving unscheduled flows priority access
over the rights paid for by OATT customers (scheduled flows). For example, during the RBC trial in
the West, the number of curtailments to e-tags went up dramatically as a result of unscheduled flows
across path 36, as reported by the WECC Performance Workgroup in the December 2011 Quarterly
Report on the RBC Field Trial. Most recently, we have seen a record number of curtailments across
path 66. In 2011, there were a total of 61 Path 66 events of Step 4 or higher (see WECC Unscheduled
Flow Reduction Guideline). Already in 2012, we have seen 741 Path 66 events of step 4 or higher (as
of mid June). It is a significant concern that the higher unscheduled flows resulting from the RBC field
trial are contributing to the curtialments. If the proposed standard is approved it should be expected
that this issue will continue, and perhaps spread to other parts of the grid. (We discuss this issue in
more detail in our response to Question 11.) Also of concern is the dramatic impact that the proposed
BAAL limit will have on the frequency error of the Interconnections. In WECC specifically, it has been
shown that the frequency error has been steadily increasing since the start of the RBC field trial. As
the drafting team has pointed out in the Background Document for this proposed standard, reliability
is reduced when Interconnection frequency is moved farther from the scheduled value. In light of the
fact that replacing CPS2 with the proposed BAAL limit has already been shown to have the effect of
moving the frequency away from the scheduled frequency value, the adoption of proposed standard
would have the overall effect of reducing reliability. We would also like to note that, under the WECC
field trial, BAs that are operating with BAAL have been requested by the Reliability Coordinator to
further limit their ACE due to transmission overload issues in the Interconnection caused by the
operations of another BA (e.g. BA #1 is interconnected with BA#2, and BA#1’s inadvertent flows
cause an SOL violation at the interconnection between BA#2 and BA#3, so the RC requests BA#2 to
change their operation). This should be a serious concern: A BA operating in compliance with the
proposed BAL-001 reliability standard (during the RBC field trial) is causing or contributing to a
violation of another reliability standard (TOP) and potentially causing another entity to be in violation.
No
No
No. As stated above in our response to Question 5, because of the significant deficiencies of
Requirement 2, a BA would be able to operate in a way that could have a significant impact on
reliability, for the majority of the time, without facing any penalty or sanction.
No
No. As stated above in our response to Question 5, because of the significant deficiencies of
Requirement 2, a BA would be able to operate in a way that could have a significant impact on
reliability, for the majority of the time, without facing any penalty or sanction.
No
No. Powerex feels the Background Document does not reference or explain any of the findings of the
RBC trial discussed in Question 5 that should be of concern, i.e. BAs operating outside the BAAL limit
in a cyclical manner, the detrimental impact of unscheduled flows on the grid, and the increase in
frequency error.
In Order No. 890, the Federal Energy Regulatory Commission (FERC or the Commission) recognized
the potential for unscheduled energy flows between adjacent BAAs both to jeopardize reliability and to
cause undue harm to customers on the grid. The Commission stated, at P 703, in regards to the
existing framework for inadvertent energy: “However, if there is evidence that it is no longer
sufficient to maintain reliability, or is allowing certain entities to lean on the grid to the detriment of
other entities, the Commission has authority under FPA section 215 to direct the ERO to develop a
new or modified standard to address the matter." Powerex believes that the development of the BAL001 standard based on the current purpose statement will allow entities to create deliberate
inadvertent flows within the standards boundaries, without regard to the impact to transmission
customers on the grid. This may result in substantial curtailments to transmission customers in direct
contravention of the Commission’s open access transmission principles of Order 890. BAL-001 may
also be in conflict with FERC Order 693 (P 397). In that order, the Commission noted that while the
control performance standard metric (BAAL limit in R2) is useful in identifying trends relating to poor
regulating practices, specification of minimum reserve requirements to be maintained at all times
would complement the control performance standard metrics by providing real-time requirements
necessary for proper control. “[T]he control performance standard metric is a lagging indicator and,

as such, does not provide a good indication that necessary amounts of regulating reserve are being
carried at all times.” The capability to be able to meet a BA’s expected intra-hour imbalances, with a
significant degree of confidence, should be achieved prospectively each hour. It is not sufficient to
reduce a BA’s regulation to a level designed only to meet the performance standards retrospectively.
Though a prospective balancing reserve requirement as contemplated in Order 693 may be missing
from standards currently in place, the inherent limits in the current CPS2 are strict enough such that
the need for a prospective minimum requirement is reduced. However, the relaxation of the control
performance measures in BAL-001 make it imperative that the minimum reserve requirements
contemplated in Order 693 are included.
The recent increase in intermittent resources, such as wind and solar generation, has increased
balancing challenges due to variability in generation, driving actual generation to differ from
scheduled generation. By eliminating CPS2 and replacing it with the relaxed BAAL limit, the proposed
performance standard does not address the potential for a single BA to lean on the grid with
deliberate unscheduled energy flows or inadvertent energy, taking any accumulated benefits for itself
and possibly even jeopardizing reliability and/or harming other entities on the grid. The detrimental
impacts of deliberate inadvertent flows to load customers and transmission customers on the grid
could be substantial. Price signals generally drive correlated behavior across multiple market
participants. Load customers could have service interrupted if multiple BAs, following market price
signals, all decided to inaccurately schedule their expected hourly average generation in the same
direction in the same hour, without sufficient prospective ability to restore and sustain “balance”
within the BAA, if needed. Transmission customers are likely to be frequently interrupted due to
unscheduled flows, if one or more BAs take advantage of the BAAL limit and deliberately rely on
inadvertent energy to meet their expected BAA imbalances, as BAA imbalances can undisputedly
occur without knowledge or regard to transmission availability or coordination. In order 890, FERC
made it clear that it was inappropriate for generators within a BAA to “dump power on the system or
lean on other generation…The tiered imbalance penalties adopted in the Final Rule generally provide a
sufficient incentive not to engage is such behavior”. The Commission unambiguously wanted to
encourage accurate scheduling of a generator’s output within a BAA. Though at the time of the 890
ruling the Commission chose not to impose similar rules preventing BAs themselves and their affiliate
generators from leaning on the grid, they recognized that there was a potential for such behavior, and
noted that it could take action under FPA section 215 if such deliberate inadvertent flows were
degrading reliability or harming other customers. These issues have brought to the forefront the
importance of the public release of BAA-specific hourly inadvertent flow data. The inadvertent flows
resulting from the operations of one BAA can have a significant impact on its neighboring BAAs and
the transmission customers on the grid. Powerex feels it public release of the hourly inadvertent flow
data would give all entities a better understanding of the way the BAAs are operating in their region
and facilitate coordinated operations to ensure the adverse impacts of inadvertent flows can be
appropriately minimized. The broader wholesale electricity grid may be a valuable balancing resource
for both reducing the wear and tear on dispatchable generation resources. However, it is imperative
to reliability, open access transmission principles, and proper functioning wholesale energy markets,
that increased utilization of the electricity grid’s inherent transmission flexibility and inherent
frequency flexibility be achieved within an appropriate framework. More specifically, before
implementing the BAAL limits in BAL-001 and allowing BAs to use the broader electricity grid
deliberately as a balancing resource, by either reducing the amount of balancing reserves dispatched,
and/or potentially reducing the amount of balancing reserves carried, the following may be required:
1. Enforceable rules and processes that ensure that BAA imbalances can be immediately limited if
applicable transmission flowgate limits are reached. Unscheduled energy flows resulting from BAA
imbalances should clearly have the lowest priority access to transmission, behind all customers who
have invested, and appropriately scheduled, to use the transmission network. 2. Minimum BA
balancing reserve requirements, set prospectively, to ensure that the amount of balancing reserves
carried on the broader grid are sufficient to maintain grid reliability. Reliance on performance
standards, as a lagging indicator, may be insufficient to ensure reliability on a prospective basis,
particularly as such performance standards become more liberal such as with the proposed BAAL
limits. In Order 693, FERC noted that while the control performance standard metric like Requirement
2, is useful in identifying trends relating to poor regulating practices, specification of minimum reserve
requirements to be maintained at all times would complement the control performance standard
metrics by providing real-time requirements necessary for proper control. FERC directed the ERO to
develop a process to calculate the minimum regulating reserve for a BA, taking into account expected

load and generation variation and transactions being ramped into or out of the BA. 3. The benefits of
utilizing the flexibility in the grid are appropriately allocated to all grid participants, through either
BAA consolidation or BAA coordination frameworks, and FERC cost allocation oversight. Individual
BAAs should not be able to lean on the grid disproportionally, hoping that there are sufficient BAs with
a more conservative approach to Good Utility Practice to maintain the grid’s reliability, at their
customers’ inequitable expense. 4. Hourly BAA imbalance data is made public (after-the-fact, in a
similar manner to the way scheduled transmission usage is released on OASIS), so that NERC, the
Regional Entities, BAs, impacted transmission customers, etc, can use the data to monitor the
inappropriate use of unscheduled flow. Unless BAL-001 (or the framework made up by the BARC
standards) includes requirements for performance in a manner that prevents an entity from
deliberately leaning on the grid to gain commercial advantage, it would be inappropriate to adopt the
standard in its present form.
Individual
Michael Falvo
Independent Electricity System Operator
Yes
Yes
While we agree with these four entities comprise the four major Interconnections, the term is used
scores of times in other standards. It is beyond the scope of this drafting team to redefine
expectations of other standards.
Yes
Yes
Yes
Yes
Yes
Yes
No
While it is not material to the new standard, the A1 criterion is not properly stated. Under A1, ACE
needed to cross zero at least once in every ten minute period of the hour and that the total noncrossings had to be less than 10 percent of all periods.
Sections 4.1.1 and 4.1.2 are unclear as to which entities are subject to complying with the standard.
Further, the word “calculates” in both Sections turn these Sections into requirements rather than
specifying the entities being responsible for meeting Requirements R1 and R2. Inferring from Section
4.1.3, we interpret these Sections to mean that the “Balancing Authority that provides Overlap
Regulation Service to another Balancing Authority”. In that case, a requirement to hold the service
providing BAs responsible for calculating its CPS1 performance after combining its Reporting ACE and
Frequency Bias Settings with the Reporting ACE, and Frequency Bias Settings of the Balancing
Authority receiving the Regulation Service, would be necessary. Same applies to the BAAL calculation
implied in Section 4.1.3.
Group
Associated Electric Cooperative Inc, JRO00088
David Dockery
Yes
Reporting ACE definition: Replace: “the difference between the Balancing Authority’s actual

interchange and its scheduled interchange plus its frequency bias obligation plus any unknown meter
error” With: “control-error consideration of: interchange, frequency, and interchange-metering
errors.” Rationale: This simplified description may explain more without restating the equation.
Yes
No
AECI agrees with the posted for ballot Project_2010-14-1_BAL-0011_Standard_Clean_20120604_final_rev1 copy, where “in support of interconnection frequency.” is
deleted.
Yes
AECI agrees with this existing and unmodified requirement.
No
AECI is fine with the wording under R2, but not strongly recommends that Attachment 2 be changed
as follows: Replace: “60 Hz” or “60” With: “Fs” And reinstate: the earlier Fs definition Rationale: 1) As
currently drafted, this standard penalizes BAs who are complying with directed time-error corrections,
2) This draft was only appropriate when our industry believed that time-error corrections would be
retired, and 3) any concern, about time-error corrections being so large that they risk UFL first-tier
margins, should be addressed by exercising smaller magnitude corrections for longer periods of time.
No
AECI concurs with the concerns expressed by SERC on behalf of smaller BAs.
Yes
Yes
Yes
No
AECI agrees with SERC comment that Attachment 1 Interconnection names should agree with those
in the draft Interconnection definition.
Group
ACES Power Marketing Standards Collaborators
Jason Marshall
No
We question the need for the Reporting ACE definition. There is no explanation anywhere in the
documentation for its need. Why is the definition of ACE not satisfactory? The definition is not even
consistent with the definition of ACE. The definition of ACE uses net actual interchange and net
schedule interchange. While we are sure that the Reporting ACE definition intends for these values to
be net values, questions will arise why the word “net” is included in one definition and not the other in
a compliance driven world. If the definition remains, we suggest striking everything after Area Control
Error. Everything after this is already included in the definition of ACE to which this definition refers.
The only difference between the two definitions appears to be that one is “instantaneous” and the
other is a “scan rate”. We think “scan rate” is nearly instantaneous and satisfies the definition
particularly since it is the only way to measure ACE and considering there are other requirements
(BAL-005-0.1b R8) that specify ACE only has to be calculated (which requires scanning of tie-line
measurements) once every six seconds. The bottom line is that the definition does not offer additional
clarity. Furthermore, we recommend that the ACE definition should be modified to include the ACE
calculation from the standard. The equation really should be the definition as it is much more
descriptive than the words provided in the definition.
Yes
No
We think the purpose statement should be modified to state that it is steady-state frequency that is

being controlled. Otherwise, transient frequencies are included which is problematic considering even
stable swings in frequency could easily exceed the frequency bounds established in the standard.
Yes
We thank the drafting team for making it perfectly clear that only the rolling 12 month CPS1
calculation is subject to compliance and not the one month calculation.
Yes
Conceptually, we are in complete agreement with the BAAL limit. It is far superior to the CPS2
requirements. The BAAL limits consider frequency impact whereas CPS2 does not. At times, CPS2
forces a BA to move its ACE in a direction that does not support frequency. Furthermore, control for
CPS2 could be turned off for 10% of the time (over a month) and a BA could still be compliant. While
we agree with the requirement, some further clarification is required regarding the exclusion of oneminute samples as explained in Attachment 2. Since a violation is based on consecutive clock
minutes, what should the responsible entity assume about clock-minute samples that are excluded
because less than 50% of the data is available per Attachment 2? If responsible entity is exceeding a
BAAL high limit for 10 minutes, then fails to record the next 8 clock-minute samples because of data
unavailability, and then exceeds the same BAAL high limit for the following 13 minutes, is this a
violation?
Yes
Yes
Yes
Yes

The implementation plan states that six months are required to make software changes to an EMS to
accommodate the change to the standard. Is this based on the actual experience of those
participating in the field trial? If not, the drafting team should reach out to the field trial participants
to find out how long it took them to implement the changes. If it is, the documentation should state
this clearly. In the first paragraph in the background and rationale section on page 4 of the
background document, “Compliance Performance Standard” should be “Control Performance
Standard”. We think the new variation on the meter error term in the ACE equation is actually more
confusing than the previous meter error term. The previous term was clear that hourly integration of
the instantaneous meter values was being compared to the revenue quality meters. The new term
does not state this as clearly. ACE needs to be capitalized in the second paragraph of the Data
Retention section. To the extent that a responsible entity is subject to periodic reporting that will
demonstrate compliance, we question the need for a data retention period of one full year. No more
than three months of BAAL data should be required We disagree with requiring data to be retained for
up to four years. First, the current standard only required the BA to retain the data for one year. No
justification has been provided for raising the bar. Second, NERC receives periodic reports for CPS1
and currently for the BAAL limits. Thus, they can retain these reports if they need them. One year is
sufficient time for NERC to raise any issues or questions about the input data used in the calculation
for CPS1 and the BAAL limits. If no issues have arisen to cause NERC to request data retention for a
longer period within the first year, then the responsible entity should not be required to retain it.
Third, retention of data beyond the three year BA audit cycle is not consistent with NERC Rules of
Procedure. Section 3.1.4.2 of Appendix 4C – Compliance Monitoring and Enforcement Program states
that the compliance audit will cover the period from the day after the last compliance audit to the end
date of the current compliance audit. The minimum resolution for actual frequency in Attachment 2
should be removed. First, it is essentially a requirement and requirements cannot be written into
attachments. Second, it raises the bar over the frequency measurement accuracy established in BAL005-0.1b R17 without justification.
Individual
Joe Tarantino

Sacramento Municipal Utility District
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes

Individual
Daniel O'Hearn
Powerex Corp.
Yes
Yes
No
No, the Purpose Statement is inadequate. The purpose of the standard should be to control BAA ACE
within defined limits in support of Interconnection Frequency, and to prevent BAA ACE from having a
detrimental impact to other entities on the grid. In Order No. 890, the Federal Energy Regulatory
Commission (FERC or the Commission) recognized the potential for inadvertent energy flows between
adjacent BAs to both jeopardize reliability and to cause undue harm to customers on the grid. Such
inadvertent energy flows are driven by the size of each BAAs ACE, as primarily contained by CPS2
under the current BAL-001, and the new proposed BAL-001 standard. Powerex believes that the
development of the BAL-001 standard based on the current purpose statement will allow entities to
create deliberate inadvertent flows within the standards boundaries, without regard to the impact to
transmission customers on the grid. This may result in substantial curtailments to transmission
customers in direct contravention of the Commission’s open access transmission principles.
Yes
No
No. The standard is inadequate. The requirement will allow BA’s to operate in a way that could
significantly increase risk to the interconnection, for up to 30 minutes, without penalty. Worse, it will
allow BA’s to “sawtooth”: operate outside the BAAL limit for extended periods of time (up to 30
minutes), change operations for as little as one minute to bring their ACE back into the BAAL limit to
reset the 30 minute clock, and then again start operating outside the BAAL limit, and do so cyclically,
for extended periods. This behavior was exhibited to some extent by several BAsduring the field trial,
so there should be every expectation that this type of behavior will continue, if not spread and
worsen, if this new standard was put in place. In the Background Document for the standard the

drafting team pointed out that CPS2 “… allows significant hours when a Balancing Authority’s ACE
values are unbounded.” Because R2 of the proposed standard will allow BAs to cyclically operate
outside the BAAL limit as described above, the problem of BA’s operating with an unbounded ACE
could actually become worse under the proposed standard, not better. Powerex notes that no
technical justification has been put forward as to why a BAA should be able to operate outside the
BAAL limit for 30 minutes. We recommend that the drafting team consider a shorter period (e.g. 5
minutes). As well, to prevent the sawtoothing behavior, Powerex recommends that a monthly
maximum be set on the number of times a BAA can exceed the BAAL limit (e.g. 5 times per month).
Another concern is that the requirement will allow unlimited unscheduled flow, across interties when
the actual system frequency is close to the scheduled frequency. There seems to be a disregard for
the fact that unscheduled flows can have a significant detrimental impact on scheduled flows.
Curtailments to scheduled flows is one of the main tools used to keep the system operating within
limits during period of high unscheduled flows, effectively giving unscheduled flows priority access
over the rights paid for by OATT customers (scheduled flows). For example, during the RBC trial in
the West, the number of curtailments to e-tags went up dramatically as a result of unscheduled flows
across path 36, as reported by the WECC Performance Workgroup in the December 2011 Quarterly
Report on the RBC Field Trial. Most recently, we have seen a record number of curtailments across
path 66. In 2011 there were a total of 61 Unscheduled Flow Mitigation events for Path 66 of Step 4 or
higher (see the WECC USF Mitiagation Procedure). So far in 2012 there have already been 741 events
of step 4 or highter. It is a serious concern that the increase in unscheduled flow across path 66 can
be attributed to the the RBC field trial (i.e. the BAAL limit). If the proposed standard is approved it
should be expected that this issue will continue, and perhaps spread to other parts of the grid. (We
discuss this issue in more detail in our response to Question 11.) Also of concern is the dramatic
impact that the proposed BAAL limit will have on the frequency error of the Interconnections. In
WECC specifically, it has been shown that the frequency error has been steadily increasing since the
start of the RBC field trial. As the drafting team has pointed out in the Background Document for this
proposed standard, reliability is reduced when Interconnection frequency is moved farther from the
scheduled value. In light of the fact that replacing CPS2 with the proposed BAAL limit has already
been shown to have the effect of moving the frequency away from the scheduled frequency value, the
adoption of proposed standard would have the overall effect of reducing reliability. We would also like
to note that, under the WECC field trial, BAs that are operating with BAAL have been requested by the
Reliability Coordinator to further limit their ACE due to transmission overload issues in the
Interconnection caused by the operations of another BA (e.g. BA #1 is interconnected with BA#2, and
BA#1’s inadvertent flows cause an SOL violation at the interconnection between BA#2 and BA#3, so
the RC requests BA#2 to change their operation). This should be a serious concern: A BA operating in
compliance with the proposed BAL-001 reliability standard (during the RBC field trial) is causing or
contributing to a violation of another reliability standard (TOP) and potentially causing another entity
to be in violation.
No
No comment at this time.
No
No. As stated above in our response to Question 5, because of the significant deficiencies of
Requirement 2, a BA would be able to operate in a way that could have a significant impact on
reliability, for the majority of the time, without facing any penalty or sanction.
No
No. As stated above in our response to Question 5, because of the significant deficiencies of
Requirement 2, a BA would be able to operate in a way that could have a significant impact on
reliability, for the majority of the time, without facing any penalty or sanction.
No
No. Powerex feels the Background Document does not reference or explain any of the findings of the
RBC trial discussed in Question 5 that should be of concern, i.e. BAs operating outside the BAAL limit
in a cyclical manner, the detrimental impact of unscheduled flows on the grid, and the increase in
frequency error.
In Order No. 890, the Federal Energy Regulatory Commission (FERC or the Commission) recognized
the potential for unscheduled energy flows between adjacent BAAs both to jeopardize reliability and to
cause undue harm to customers on the grid. The Commission stated, at P 703, in regards to the

existing framework for inadvertent energy: “However, if there is evidence that it is no longer
sufficient to maintain reliability, or is allowing certain entities to lean on the grid to the detriment of
other entities, the Commission has authority under FPA section 215 to direct the ERO to develop a
new or modified standard to address the matter." Powerex believes that the development of the BAL001 standard based on the current purpose statement will allow entities to create deliberate
inadvertent flows within the standards boundaries, without regard to the impact to transmission
customers on the grid. This may result in substantial curtailments to transmission customers in direct
contravention of the Commission’s open access transmission principles of Order 890. BAL-001 may
also be in conflict with FERC Order 693 (P 397). In that order, the Commission noted that while the
control performance standard metric (BAAL limit in R2) is useful in identifying trends relating to poor
regulating practices, specification of minimum reserve requirements to be maintained at all times
would complement the control performance standard metrics by providing real-time requirements
necessary for proper control. “[T]he control performance standard metric is a lagging indicator and,
as such, does not provide a good indication that necessary amounts of regulating reserve are being
carried at all times.” The capability to be able to meet a BA’s expected intra-hour imbalances, with a
significant degree of confidence, should be achieved prospectively each hour. It is not sufficient to
reduce a BA’s regulation to a level designed only to meet the performance standards retrospectively.
Though a prospective balancing reserve requirement as contemplated in Order 693 may be missing
from standards currently in place, the inherent limits in the current CPS2 are strict enough such that
the need for a prospective minimum requirement is reduced. However, the relaxation of the control
performance measures in BAL-001 make it imperative that the minimum reserve requirements
contemplated in Order 693 are included.
The recent increase in intermittent resources, such as wind and solar generation, has increased
balancing challenges due to variability in generation, driving actual generation to differ from
scheduled generation. By eliminating CPS2 and replacing it with the relaxed BAAL limit, the proposed
performance standard does not address the potential for a single BA to lean on the grid with
deliberate unscheduled energy flows or inadvertent energy, taking any accumulated benefits for itself
and possibly even jeopardizing reliability and/or harming other entities on the grid. The detrimental
impacts of deliberate inadvertent flows to load customers and transmission customers on the grid
could be substantial. Price signals generally drive correlated behavior across multiple market
participants. Load customers could have service interrupted if multiple BAs, following market price
signals, all decided to inaccurately schedule their expected hourly average generation in the same
direction in the same hour, without sufficient prospective ability to restore and sustain “balance”
within the BAA, if needed. Transmission customers are likely to be frequently interrupted due to
unscheduled flows, if one or more BAs take advantage of the BAAL limit and deliberately rely on
inadvertent energy to meet their expected BAA imbalances, as BAA imbalances can undisputedly
occur without knowledge or regard to transmission availability or coordination. In order 890, FERC
made it clear that it was inappropriate for generators within a BAA to “dump power on the system or
lean on other generation…The tiered imbalance penalties adopted in the Final Rule generally provide a
sufficient incentive not to engage is such behavior”. The Commission unambiguously wanted to
encourage accurate scheduling of a generator’s output within a BAA. Though at the time of the 890
ruling the Commission chose not to impose similar rules preventing BAs themselves and their affiliate
generators from leaning on the grid, they recognized that there was a potential for such behavior, and
noted that it could take action under FPA section 215 if such deliberate inadvertent flows were
degrading reliability or harming other customers. These issues have brought to the forefront the
importance of the public release of BAA-specific hourly inadvertent flow data. The inadvertent flows
resulting from the operations of one BAA can have a significant impact on its neighboring BAAs and
the transmission customers on the grid. Powerex feels it public release of the hourly inadvertent flow
data would give all entities a better understanding of the way the BAAs are operating in their region
and facilitate coordinated operations to ensure the adverse impacts of inadvertent flows can be
appropriately minimized. The broader wholesale electricity grid may be a valuable balancing resource
for both reducing the wear and tear on dispatchable generation resources. However, it is imperative
to reliability, open access transmission principles, and proper functioning wholesale energy markets,
that increased utilization of the electricity grid’s inherent transmission flexibility and inherent
frequency flexibility be achieved within an appropriate framework. More specifically, before
implementing the BAAL limits in BAL-001 and allowing BAs to use the broader electricity grid
deliberately as a balancing resource, by either reducing the amount of balancing reserves dispatched,
and/or potentially reducing the amount of balancing reserves carried, the following may be required:

1. Enforceable rules and processes that ensure that BAA imbalances can be immediately limited if
applicable transmission flowgate limits are reached. Unscheduled energy flows resulting from BAA
imbalances should clearly have the lowest priority access to transmission, behind all customers who
have invested, and appropriately scheduled, to use the transmission network. 2. Minimum BA
balancing reserve requirements, set prospectively, to ensure that the amount of balancing reserves
carried on the broader grid are sufficient to maintain grid reliability. Reliance on performance
standards, as a lagging indicator, may be insufficient to ensure reliability on a prospective basis,
particularly as such performance standards become more liberal such as with the proposed BAAL
limits. In Order 693, FERC noted that while the control performance standard metric like Requirement
2, is useful in identifying trends relating to poor regulating practices, specification of minimum reserve
requirements to be maintained at all times would complement the control performance standard
metrics by providing real-time requirements necessary for proper control. FERC directed the ERO to
develop a process to calculate the minimum regulating reserve for a BA, taking into account expected
load and generation variation and transactions being ramped into or out of the BA. 3. The benefits of
utilizing the flexibility in the grid are appropriately allocated to all grid participants, through either
BAA consolidation or BAA coordination frameworks, and FERC cost allocation oversight. Individual
BAAs should not be able to lean on the grid disproportionally, hoping that there are sufficient BAs with
a more conservative approach to Good Utility Practice to maintain the grid’s reliability, at their
customers’ inequitable expense. 4. Hourly BAA imbalance data is made public (after-the-fact, in a
similar manner to the way scheduled transmission usage is released on OASIS), so that NERC, the
Regional Entities, BAs, impacted transmission customers, etc, can use the data to monitor the
inappropriate use of unscheduled flow. Unless BAL-001 (or the framework made up by the BARC
standards) includes requirements for performance in a manner that prevents an entity from
deliberately leaning on the grid to gain commercial advantage, it would be inappropriate to adopt the
standard in its present form.
Individual
Anthony Jablonski
ReliabilityFirst

ReliabilityFirst offers the following comment for consideration: 1. Applicability section a. RFC seeks
further clarity surrounding the applicability of Balancing Authorities which do not provide Regulating
Service. If a Balancing Authority does not provide Regulating Service, are they subsequently not
subject to the requirements in the standard? If they are not subject to the requirements in the
standard, RFC recommends removing section 4.1.3 since it is not needed as well.
Individual
Jeff Harrison
AECI
Yes
Yes
No
Delete “in support of interconnection frequency”.
Yes

No
AECI would like to request a modification to Attachment 2, such that the this calculation uses the
scheduled frequency and not a constant of 60.0. Such that the BAAL calculation will adjust for time
error correct.
No
VRFs should be adjusted based upon the balancing authorities impact upon the interconnection.
Yes
Yes
Yes

Individual
Greg Travis
Idaho Power Company
Yes
Although WECC is pursuing a Regional Variation to include the WECC ATEC term into the reporting
ACE which is needed.
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
None.
None
Individual
Michael Goggin
American Wind Energy Association
Yes
Yes
Yes
Yes

Yes
Yes
Yes
Yes
Yes

Based on the experience of the pilot program, this proposed standard will likely allow grid operators
to maintain reliability while reducing the need for regulation reserves needed to accommodate all
sources of variability on the power system. As a result, the proposed standard should be supported.
Group
Progress Energy
Jim Eckelkamp
Yes
Yes
No
It is not clear that this Standard aids in the control of frequency within defined limits, particularly for
transient frequency deviations to avoid UFLS operation. Conclusive results of the BAAL field trial are
not provided in the background document. If the industry is to make the move to make this change,
there should be evidence provided that this action will aid in better frequency control for the
Interconnections.

No
Conclusive results of the BAAL field trial are not provided in the background document. If the industry
is to make the move to make the change from CPS2 to BAALs, there should be evidence provided that
this action will aid in better frequency control for the Interconnections.
Absent CPS2 L10 limits, at any given time one BA has no incentive to manage its ACE and can take
advantage of the regulating power of neighboring BAs who may be balancing more effectively. CPS1
remains in place, however, this is a rolling one-year average and does not provide the same incentive
as CPS2. BAL-001-1 Attachment 1 proposes to define actual frequency as “FA (Actual Frequency) is
the measured frequency in Hz, with minimum resolution of +/- 0.005 Hz.” This proposal includes an
unreasonable resolution for frequency measurements and is unnecessary. Accuracy of frequency
devices that are used in the calculation of ACE is already required by Standard BAL-005-1
Requirement 17. Further, providing this proposed required resolution on some existing industry
equipment would either not be possible or would cause the total bandwidth for which the frequency
can be monitored to be reduced to a level that would be unfavorable. The basis or rationale for this
proposed resolution is not discussed in the background document and, and this requirement should
be deleted from the Standard
Individual

Thad Ness
American Electric Power
No
The definition for the term Balancing Authority ACE Limit (BAAL) implies there is always a reliability
risk for exceeding the limit, without taking into consideration relative operating conditions at the time.
Merely exceeding an ACE Limit (BAAL) does not always constitute that there is an inherent reliability
risk, as that would depend on the actual operating conditions and timing of the occurrence and/or
normal frequency characteristics on that operating day. For example: High Frequency prior to an
extreme morning load pickup with Net Scheduled Interchange out, and Low Frequency prior to nightly
fall off are sometimes a more favorable reliability condition. We recommend changing the text to read
“The limit beyond which a Balancing Authority contributes more than its share of Interconnection
frequency control’s allotted reliability deviation for required measure”. We agree with the definition of
the term Reporting ACE, however, it should be noted that Balancing Authorities with membership to
some Regional Power Pools use an added factor of ACE diversity component in their Reporting ACE
beyond what is mentioned.
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes

There needs to be an understanding and appreciation of the increasing number of newly-registered
market participant Generator Operators that are not from the traditional, vertically integrated utility
environment, and their impact on a Balancing Authority’s ability to balance. We encourage the SDT to
think of opportunities to develop appropriate requirements in order to ensure that Generator
Operators can help support the objectives of balancing load and generation in a reliable manner. The
background information on balancing sometimes refers back to the former “NERC Policy”, at a time
when the preceding “Control Area” model applicability had different operating characteristics than
today’s more granular functional model entity in terms of Balancing Authority, Generator Operator,
Load Serving Entity (Demand Side Load Management), Market Operator, etc. The stated compliance
applicability within the proposed Standard fails to address inherent impact of these other functional
entities and variables on a Balancing Authority’s sole ability to comply with these requirements in
today’s actual practice. Balancing Authorities that are part of regional energy and/or ancillary service
markets may have unique challenges with respect to deployment of Balancing Authority resources.
For example, the failure of following market deployment may only involve a financial market charge,
however the results could have significant impact on Balancing Authority obligations.
Individual
Chris Mattson
Tacoma Power
Yes

Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes

Group
MRO NSRF
WILL SMITH
No
The definition of reporting ACE is nearly identical to the current definition of ACE, but the appendix
adds complexity. There should be no need for this new definition. The description of the definition in
the attachment is overly prescriptive. It has a redundant and more restrictive requirement for
frequency resolution than BAL-005. It also created a new term, Net Metering Error that is more
prescriptive than how metering error is corrected for today.
Yes
While the NSRF agrees with these four entities comprise the four major Interconnections, the term is
used scores of times in other standards. It is beyond the scope of this drafting team to redefine
expectations of other standards.
Yes
Yes
While the NSRF agrees that the 12 month rolling average performance is evaluated monthly, that
does not mean that substandard performance in one month should result in many months of repeat
violations until that bad month rolls out the average. Non-compliance should only accrue if the BA is
not under a mitigation plan and has new months of non-compliant performance.
Yes
The NSRF supports R2 as an improved approach over CPS2. While not under the purview of this
drafting team, the proposed changes in BAL-003 with regard to variable bias (no floor on variable
bias) opens the opportunity for gaming R2.
Yes
Yes
Yes
The drafting team may want to look at how small BAs are impacted by R2. The CPS curve for small
BAs has a wider tail. The performance expectations may not be the same.
No

While it is not material to the new standard, the A1 criterion is not properly stated. Under A1, ACE
needed to cross zero at least once in every ten minute period of the hour and that the total noncrossings had to be less than 10 percent of all periods.
General Comments and Observations • The drafting team changed the NERC definition of
Interconnections. This term is used in many standards and may have impact on them. • The reporting
ACE term that the team created seems unnecessary as ACE is already defined. It also expands on the
expectations of ACE. The frequency resolution appears too tight 0.0005Hz (compared to 0.001 in
BAL-005) and the new term, Net Metering Error is prescriptive on how metering error is corrected.
Group
Northeast Power Coordinating Council
Guy Zito

No
As with BAL-013-1, should “clock-minutes” be replaced with “minutes”?

Because the frequency model is simply using 3 times Epsilon 1 for trigger limits, it does not produce
optimum results. The 3 times Epsilon 1 trigger limits are not calibrated to account for relay settings or
frequency response. The 3 times Epsilon 1 approach has a “set it and forget it” characteristic. The
alternative model would require periodic updating as relay limit settings change, the Interconnection’s
frequency response changes, and the perceptions of the level of protection needed change. It also
does not target a specified level of reliability. Concerns about transmission limits caused by dropping
CPS 2 and the limitations in CPS 1 still haven’t been addressed. For CPS 1 data submissions, the
number of one minute samples in the month becomes a new requirement. In Attachment 2 more
complete guidance is needed for the treatment of a missing one minute sample when counting the
time expired during a BAAL limit violation. Which of the following assumptions should be made about
the missing sample: compliance, non-compliance, same state as the previous sample, same state as
the next sample, or simple omission?
Group
Arizona Public Service Company
Janet Smith, Regulatory Affairs Supervisor
Yes
Yes
Yes
Yes
No
AZPS has not been convinced that the RBC is a better form of control then what is currently in place.
Yes on VRFs Since the RBC Field Trial began the WECC average frequency deviation has been
increasing. The RBC Field Trial results are not an accurate reliability assessment as not all
participating Balancing Area’s Energy Management Systems have CPS1-only control capability and,
thus, are not fully participating. CPS2 is designed to limit a Balancing Area’s unscheduled power flows

and does not have a frequency component – that is what CPS1 is designed to measure. The new
BAAL standard will allow far more unscheduled power flows when the Interconnection frequency
remains near nominal, which it predominately does. CPS2 allows a Balancing Area to be noncompliant for 72 hours (10%) each month. Under the proposed BAAL standard, a Balancing Area can
be non-compliant twenty-nine minutes of each 30 minute period which is 696 hours (96%) per
month. This will be taken advantage of to the detriment of reliability.
Yes
Yes
No
While “reliability issues” have not been identified by the RCs, there are other issues that need to be
addressed that are not mentioned in the background document.
Yes
Yes, provides clarity but there remains disagreement with the rationale.
None noted
No comments
Individual
John Tolo
Tucson Electric Power
No
There should be an equation or formula included with the definition
Yes
Somewhat vague definition. It's more identifying the interconnections.
No
This purpose statement does not match the purpose statement in the proposed Standard.
No
There appears to be no change in CPS1 calculations or requirements so the current BAL-001-0.1a is
preferred.
No
While I agree with the theory of BAAL, and the 30 minute limit, the BAAL calculation needs to address
the fact that the BAAL for small BAs can be more restrictive than the current CPS2.
Yes
No
Need to address the BAAL calculation for small BAs
Yes
No
While I agree overall with the background document, there have been some transmission flow issues
reported from the Western Interconnection RCs. To make a statement that there have been no
reported reliability issues may not be entirely correct. I agree that BAAL has a more positive effect on
interconnection frequency than does CPS2. BAAL with some sort of transmission limit might be the
way to go.
no
Please note and read the WECC PWG report on RBC. Thanks to the drafting team for their efforts.
Individual
Kathleen Goodman
ISO New England Inc
No

Please see additional comments provided.
Yes
Yes
No
We believe that the frequency model and its use of 3*Epsilon for frequency trigger limits has
significant shortcomings. The level of reliability targeted and achieved is a function of underfrequency
relay settings, interconnection frequency response, and the size and expected outage rate of the
design contingency(s) for which protection is needed. 3*Epsilon is not sensitive to these values or
changes in them over time. It is not coordinated with the model in the Frequency Response Standard
under development, which does address these sensitivities. We are concerned that CPS 1 alone will
not address adequately the time of day short term frequency excursions observed on the Eastern
Interconnection. Additionally, we continue to have reliability concerns with the BAAL limits not
accounting for large ACE excursions and the possibility for an increase in transmission limit
exceedences associated with such operation. We believe the Interconnection will be further exposed
due to the lack of ACE bounding to somehow reflect transmission limits, and continue to believe that
CPS 2 is a more reliable metric.
No
We believe that the frequency model and its use of 3*Epsilon for frequency trigger limits has
significant shortcomings. The level of reliability targeted and achieved is a function of underfrequency
relay settings, interconnection frequency response, and the size and expected outage rate of the
design contingency(s) for which protection is needed. 3*Epsilon is not sensitive to these values or
changes in them over time. It is not coordinated with the model in the Frequency Response Standard
under development, which does address these sensitivities. We are concerned that CPS 1 alone will
not address adequately the time of day short term frequency excursions observed on the Eastern
Interconnection. Additionally, we continue to have reliability concerns with the BAAL limits not
accounting for large ACE excursions and the possibility for an increase in transmission limit
exceedences associated with such operation. We believe the Interconnection will be further exposed
due to the lack of ACE bounding to somehow reflect transmission limits, and continue to believe that
CPS 2 is a more reliable metric.

No
Given the rampant need in the industry for Requests for Interpretations, Rapid Revisions, and CANs,
we believe that future Standards need to be written so that they can "stand alone" upon scrutiny.

Group
SERC OC Standards Review Group
Stuart Goza
Yes
Yes
No
Delete "in support of interconnection frequency".
Yes
This is an existing requirement and was not modified by the standard drafting team.
Yes
The SERC OC Standards Review Group is concerned that the reliability impact of violating this

requirement is proportional to the size of the balancing authority. For example, PJM, at a size of over
100,000 MW has a much more impact on reliability than SEPA, at less than 2000 MW. We do not
understand how to apply VRFs consistently. This may require splitting into multiple VRFs considering
the size of the BA.
No
See comments to No. 5 above.
Yes
Yes
Perhaps VSLs could be graded by the size of the entity in lieu of having multiple VRFs.
Yes
No.
Should the standard include reporting requirements to the RRO? On Attachment 1, the
Interconnection names need to be revised to agree with the Interconnection as stated earlier in
question 2.
Group
Southern Company
Antonio Grayson
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes

Group
Western Electricity Coordinating Council
Steve Rueckert
No
BAAL 1. It is not clear what the phrase “interconnection frequency control reliability risk “means. 2.
BAAL should be defined by the formula used just like ACE is defined by components used to calculate
ACE Reporting ACE 1. If the existing defnition of ACE in the NERC Glossary is retired, then the
proposed definition will be using the undefined term ACE which in the proposed standard is not
defined. The definition cannot refer to an undefined term. If the existing definition is not retired the
proposed new term and the existing term appear to be the same thing, and the new term would not
be necessary. 2. The proposed standard uses a new definition Reporting ACE which is a replacement

of the current definition ACE in the BAL-001 standard. While the ACE formula has been renamed as
Reporting ACE, all references to ACE in Attachment 1 of BAL-001 and in other NERC Standards have
not been changed. The term ACE is used in BAL-002, BAL-003, BAL-004-WECC-1, BAL-005 and IRO
standards. 3. The WECC Board of Directors recently approved a WECC Regional Variance to NERC
BAL-001-0.1a that would include the Automatic Time Error Correction term in the ACE definition in
the Western Interconnection. WECC is in the process of ubmitting this regional variance to NERC for
NERC BOT consideration. If approved, the reporting ACE will be different for WECC. The drafting
teama needs to be aware of this and take this into account. 4. WECC recommends that all of these
issues can be resolve if the new term Reporting ACE is eliminated and the current ACE term is
retained.
No
Texas should be replaced with ERCOT. A small portion of the state of Texas resides in the Western
Interconnection. The use of the word Texas may be confusing because of this.
No
1. The phrase “to support interconnection frequency” does not add anything to the requirement and
should be deleted. If a BA barely missed in one month but was compliant for the 12-month period,
would that BA fail to support interconnection frequency? 2. In Attachment 1 the definitions for Net
Interchange Actual and Net Interchange Schedule have been changed but they are not included in the
definition section of the standard. The SDT needs to clarify if these new definitions will replace the
existing approved definitions in the glossary 3. In attachment 1 the term NME in the ACE equation
replaces the existing term IME. The definition itself has not changed significantly but just the
acronym. WECC has Regional Standard BAL-004-WECC-1 that refers to the term IME and
recommends that the SDT retain the existing term and definition of IME. 4. The attachment 1 defines
Reporting ACE and essentially removing the definition for the term “ACE” but the formulas in
attachment 1 still refer to ACE. WECC recommends replacing the proposed Reporting ACE with ACE
which also addresses the inconsistency with all other NERC standards that refer to the term ACE. 5. It
is not clear why the calculation for CPS1 was moved from the standard to the attachment. Are
attachments part of the standard and if so must they go through the standards development
procedure if a modification of the equation is made? Will the industry be given a chance to
comment/ballot on any changes made to the formulas if they are not part of the standard. What
process will be used to change content in the attachment 1 and will the industry have opportunities to
comment and ballot on the changes?
No
1. The phrase “to support interconnection frequency” does not add anything to the requirement and
should be deleted. 2. It is not clear why the calculations for BAAL are included in attachment 2. Are
attachments part of the standard and if so must they go through the standards development
procedure if a modification of the equation is made? Will the industry be given a chance to
comment/ballot on any changes made to the formulas if they are not part of the standard. What
process will be used to change content in the attachment 1 and will the industry have opportunities to
comment and ballot on the changes?
Yes

Yes
To the extent that we believe the VSLs are appropriate for the requirements as written. However, the
VSLs will potentially need to be modified if the suggested changes are implemented.
No
The background document should include the Field Trial results from all Interconnections.
1. The BAAL formula and the calculated limits are more restrictive than current standards (CPS2 and
L10) for Balancing Authority with small frequency bias settings. The smallest frequency bias setting in
WECC is -2 MW/0.1 Hz. The limitation of BAAL to BA of this size is substantially high. For example at
59.98 the BAALLow is calculated to be -4.62 MW compared to L10 limit which is -7.66. Under the RBC
Field Trial the frequency errors and manual time error corrections have increased (WECC Report ).

Hence the frequency deviates from 60 Hz more often than in the past and the smaller BAs have to
excise more control to stay within their BAAL. The SDT needs to address the disparate treatment of
small BAs under the proposed BAAL requirement in the standard. The Priority-based Control
engineering report (PCE Report) from 2005 directed by NERC stated this issue. The report says that
the proposed BAAL may require disproportionately more control from smaller BAs than larger BAs.
Also in Table 7 under item 7 it is stated “PCE has verified that the proposed BAAL formulation ensures
that if all BAs are within their BAAL at all times, the Interconnection frequency will not exceed FTL.
Therefore, for frequency to exceed FTL, at least one BA must be outside its BAAL. However, these
features are not unique to the selected BAAL formulation; many different sets of formulations would
have the same properties. Additional research is necessary to determine the optimum BAAL
formulation. If scheduled frequency is replaced with 60 Hz in the proposed BAAL formulation, the
properties described above will no longer hold during periods of time error correction.” WECC
recommends the SDT consider developing a formula that distributes the control burden fairly among
BAs. 2. WECC has the following concerns with proposed BAAL requirement’s impact on transmission
path loading as a result of large ACE values: a) During the field trial in WECC, an increase in
Unscheduled Flow was noticed on Qualified Paths 36 and 66. In particular, during maintenance when
the limit is significantly reduced high ACE values exacerbate path loading. b) The RBC field trial in the
WECC was implemented in 3 distinct phases to test the impact on transmission path loading. Initially
the BAAL was limited to no more than 2 times L10, in phase 2 the BAAL was limited to 4 times L10;
and in phase 3 there was no cap on BAAL at 60 Hz. During Phase 3, the Reliability Coordinators (RC)
reported several SOL exceedance associated with high ACE. The SOL exceedances were mitigated
when RCs requested the high ACE value to be reduced to L10. The SDT must address transmission
loading issues caused by high ACE.
Individual
Jay Campbell
NV Energy
No
I agree with the BAAL definition. The Reporting ACE definition is too wordy, ambiguous and confusing.
To say "Scan rate values of...ACE" seems redundant. To say "measured in MW defined in BAL-001"--does one really need to define MW? Additionally, I don't see the definition. The ACE definition seems
at odds with the equation on page #7. I suggest: "Balancing Authority’s Area Control Error (ACE) is
the difference between the Balancing Authority’s actual interchange and its scheduled interchange
plus its frequency bias multiplied by the difference between actual and scheduled frquency plus any
known meter error".
Yes
No
My suggestion: "To control Interconnection frequency within defined limits."
Yes
Yes
While I generatlly agree with the intent or R2, it's too wordy. I suggest "Each Balancing Authority
shall operate such that its clock-minute average Reporting ACE does not exceed, for more than 30
consecutive clock-minutes, its clock-minute BAAL [BAAL is a defined term] for the applicable
Interconnection in which it operates. The BAAL equations are detailed in Attachment 2."
No
For R1, a VRF of medium seems excessive. A value, measured over a year, cannot "directly affect the
electrical state or the capability of the Bulk Electric System".
Yes
Yes
Yes

I am not aware of conflicts.
No.
Group
Bonneville Power Administration
Chris Higgins
No
BPA believes that the definition is subjective and only the formula should be used for the definition.
No
BPA understands that this is an update to the existing definition, but it is not a definition. This is
simply identifying the interconnections.
No
The purpose statement referenced above does not match the standard. The standard states: “To
control Interconnection frequency within defined limits”. It does not include “in support of
interconnection frequency”. Please clarify which one is correct.
No
BPA favors the previous version of the requirement. Referring to the attachment creates many
requirements within one identified requirement without breaking them out. BPA believes there should
be only one requirement within each of the identified requirements.
No
BPA disagrees with the statement in the question which says “enhance the reliability”. Referring to
the attachment creates many requirements within one identified requirement without breaking the
out. BPA believes there should be only one requirement within each of the identified requirements.
Yes
No
BPA does not agree with the requirements in general, and cannot support the measures.
Yes
No
The document mentions that there has been no reliability issues with the field trial. BPA and others in
WECC have experienced many SOL violations due to Large ACEs. BPA disagrees with the argument
that CPS2 is less reliable because you can be out of bounds for 72 hours per month. Taking the same
argument to RBC, one can be out of bounds 29 minutes, back in for a minute and out of bounds for
29 minutes. This equates to 696 hours per month. BPA believes it has been demonstrated, at least in
WECC, that CPS2 is more reliable. BPA has yet to determine if the decrease in reliability is worth the
increase in flexibility that RBC allows.
The sub-requirements of 4.1 of the applicability section contain instructions. BPA suggests that only
4.1 and 4.1.3 (a new 4.2 created) be used instead and the rest eliminated and added as a
requirement. Please refer to the WECC Reliability-based Control Field Trial Final Report July 2012
Performance Work Group Draft document. • Frequency Error • Manual Time Error Corrections •
Transmission issues • Unscheduled flow events • Small BAs In the field trial, there is direction on
when the RC should intervene during frequency deviations below the FTL. BPA believes this should be
retained either informally or formally in the standard.
Individual
Don Schmit
NPPD

No
The elimination of CPS2 has a detrimental impact on reliability because the amount of unscheduled
interchange a BA can have is not capped when frequency is in the “opposite” direction. This can lead
to transmission constraints. TOPs and RCs must have a mechanism to restrict the unscheduled flows
on the system due to a BA unilaterally over or under generating. I believe the old policies stated this
as the intent of CPS 2 (at least it was for A2). The standard is defective as written.

Group
SPP Standards Review Group
Robert Rhodes
Yes
Yes
Yes
Yes
No
We are concerned about not being able to meet the BAAL criteria during certain contingency events
exempted in BAL-002-2. For example, in the existing BAL-001-0.1a, CPS2 is a monthly average value
whereby not totally covering a multiple contingency event could be exonerated at the end of the
month provided control for the remainder of the month was sufficient to bring the monthly value to at
least 90%. With BAAL, we only have a 30-minute window of forgiveness which could create problems,
making BAAL a tighter control parameter. We would suggest at least an exemption for BAAL
compliance during events whereby multiple contingencies cause the total generation loss to be
greater than a BA’s or RSG’s MSSC.
Yes
Yes
Yes
Yes
The background document provided with BAL-001-1 provided valuable information regarding the
history of control performance criteria and how the SDT got to where it is today with the proposed
standard. What are the plans for the document? Will it become a guideline, reference document, etc?
It needs to be maintained for future reference and updating.
Not aware of any conflicts.
The effective date as proposed in the draft standard is six (6) months following approval by applicable
regulatory authorities. This is too short. We would suggest a 12-month window before the approved
standard becomes effective. This provides the BA with time to consult with EMS vendors, design and
retrofit necessary changes to existing control algorithms and testing – both acceptance testing for the
AGC changes and parallel testing alongside existing AGC systems to ensure satisfactory operation.
Currently, the BAs that are participating in the BAAL field trial are exempt from CPS2 compliance.
During the transition from BAL-001-0.1a to BAL-001-1, there need to be exemptions extended during
testing of BAAL control schemes. Currently SPP is working on a project to consolidate BAs within the

region into a single BA. The proposed completion date is scheduled for March 1, 2014. If the standard
were to become effective prior to this date, considerable expense and effort would be expended
needlessly once the consolidation takes place. Could SPP request a regional variance for exemption
from R2 until March 1, 2014?
Individual
Karen Webb
City of Tallahassee
No
The definition for BAAL introduces a new concept of “Interconnection frequency control reliability
risk”. This appears to be managing risk while the standard provides “cut and dry” limits. Suggest:
“The limit beyond which a Balancing Authority contributes more than its share of Interconnection
frequency deviation. This definition applies to a high limit (BAALHigh) and a low limit (BAALLow)."
Yes
No
The City of Tallahassee (TAL) is unsure of the clarity of this purpose statement. Suggest: To control
individual Balancing Area ACE deviation within defined limits in support of interconnection frequency.
Yes
No
While TAL agrees with the concept of the proposed language, the change in the measurement time
from BAL-001-0.1a, which was a monthly measure, to a 30-minute measure is troublesome. Each
instance of exceeding 30 minutes would be a violation. This may require changes to unit responses
that have not been a problem in the past due to the averaging of unit response over a month period.
No
The proposed M1 and M2 each allow for evidence in hard copy OR electronic format. Section D item
1.2 (Data Retention) seemingly excludes the acceptability of hard copy evidence. TAL suggests that
the Data Retention requirement be expanded to include hard copy evidence to be consistent with M1
and M2.
No
Although TAL understands from the document's Introduction that no reliability issues have been
identified in the field trial, TAL seeks additional information on the challenges encountered by the
participants during the implementation and field trial. TAL also seeks greater explanation of the field
trial results.
1. Effective Date: TAL questions whether six months is sufficient time for all EMS vendors to develop
changes to software and for all entities to successfully implement the changes within the confines of
the CIP standards, which will require multiple layers of testing outside of scheduled updates. TAL
suggests 24 months. 2. Data Retention: TAL suggests a clarification to the requirement language that
data retention is the longer of either (a) the data retention period defined in the standard or (b) the
period since the last audit. As the proposed language reads, the need to retain evidence since the
previous audit (if longer than the defined retention period) is addressed in a separate area from the
defined retention period. 3. Attachment 2: Are the Epsilon 1 values expected to change?
Individual
RoLynda Shumpert
South Carolina Electric and Gas
Yes
Yes

No
South Carolina Electric and Gas supports the comments submitted by the SERC OC Standards Review
Group
Yes
South Carolina Electric and Gas supports the comments submitted by the SERC OC Standards Review
Group
Yes
South Carolina Electric and Gas supports the comments submitted by the SERC OC Standards Review
Group.
No
Yes
Yes
South Carolina Electric and Gas supports the comments submitted by the SERC OC Standards Review
Group
Yes
No
South Carolina Electric and Gas supports the comments submitted by the SERC OC Standards Review
Group.
Individual
Don Jones
Texas Reliability Entity
Yes
There is an existing definition for “Control Performance Standard” which may need to be modified or
deleted. Additionally, it may be better to end the definition after the phrase “as defined in BAL-001,”
as using arithmetic terms (difference and plus) may not appear to match the calculation in
Attachment 1.
No
Please use “ERCOT” (not “Texas”) as the name of the Interconnection, because it does not cover the
entire state of Texas. Note that “ERCOT Interconnection” is used in Attachment 1.
No
We suggest a more precise purpose statement as follows: “To control Interconnection frequency
within defined limits by balancing real power supply and demand in real-time.”
Yes
No
ERCOT currently has a waiver for CPS2 compliance. With this new BAAL requirement, the waiver may
no longer be needed, but this needs to be evaluated further. How will this requirement be evaluated
when the BA declares an EEA? How will this requirement be evaluated if there is a generation loss
event greater than the MSSC?
Yes
There is a reference to BAL-003-1 that appears misplaced in the VRF/VSL justification document
(please verify).
Yes
Yes

1. For the applicability section, ERCOT, as the single BA for the entire interconnection, does not
provide or receive overlap regulation service from another BA. The SDT should consider adding an
additional applicability for this specific situation or re-format the section to clarify applicability to a
Balancing Authority not involved in Overlap Regulation Service. 2. Is NME consistent in use of units of
measure? (ACE is measure in MWs, but NME is “the meter error correction factor” representing a
difference in megawatt-hours). 3. Is there a maximum excluded value for one-minute sample periods
that would invalidate a CPS1 or CPS2 calculation (i.e., If 59 minutes of every hour in a month were
excluded because 50% of the one-minute period data was invalid, is the CPS1/CPS2 value
acceptable?)? Perhaps modify the “valid” requirements to be 50% of the time period under
consideration or a similar acceptable value for the time period in question (one minute, hour, day,
month…).
Individual
Nicholas L. Hall
Constellation Energy Control and Dispatch, LLC
Yes
Yes
Yes
As mentioned in later comments, the specific purpose of R2 seems to be the development of a
boundary for ACE deviation, with consideration given to frequency support. Especially given the
manner in which R2 attempts to control for frequency, its intent is clearly not the simple support or
control of frequency.
Yes
No
While the calculation of ACE performance and its impact on frequency is a positive goal, the BAAL
calculation, in its current form, does not accomplish this. Since the BAAL measure is comparing
current ACE values against a calculated average frequency value, the BAAL measure inherently allows
for BAAL to signal ACE corrections in the opposite direction of current frequency, and can and will
penalize Balancing Authorities (through negative BAAL and CPS performance) for real-time ACE
values that exceed BAAL limits, even while they are supporting current system frequency. In order to
accomplish the intended goals of the requirement – to limit ACE deviations while considering their
impact on frequency - , the BAAL measure needs to measure current actual ACE values against
current actual frequency values at the scan rate utilized for ACE/CPS calculation. Furthermore, the
trigger for when either BAALLOW or BAALHIGH is used for measure is based on actual frequency,
setting up a three part disagreement in which frequency measure is used. For example, an Actual
Frequency (as in Real Time, not averaged) of 60.1 is used to trigger BAALHIGH, which would then
measure performance against the previous minute average frequency, which could be below 60Hz,
demonstrating that the measure is not designed to accomplish its specified goals. The purpose
statement also seems slightly off base. The intention of BAAL appears to provide a measurable
boundary for ACE performance, with Frequency taken into consideration, rather than simply as a
mechanism to support system frequency, which seems to be the specific focus of the CPS1 criteria.
The purpose statement should more clearly reflect the actual intent of R2, as well as that of R1.
Yes
Yes
Yes
Yes
See comment for item 5, related to R2. If the calculation indicated for R2 is not successful in meeting
the intent of the standard, then the measures would be similarly problematic.

The Applicability section of the standard takes an unusual format. 4.1.1 and 4.1.2 seem more
appropriate as sub requirements for R1 and R2, respectively, than as applicability statements. If the
applicability section includes Balancing Authorities and Balancing Authorities Providing Overlap
Regulation Service, then 4.1.1 and 4.1.2 should move to the sub-requirements section.
Group
MISO Standards Collaborators
Marie Knox
No
The creation of a new definition, Reporting ACE, is unnecessary as Area Control Error is already a
defined term. Further, the benefit to reliability from the addition of this definition is unclear; indeed,
the addition of this definition may actually result in confusion regarding the appropriate measures for
reliable performance. Accordingly, there does not appear to be a need for this new definition.
Attachment 1 expounds upon the definition of the term Reporting ACE. This description is overly
prescriptive, redundant, and more restrictive than the performance obligations provided in
complementary Reliability Standards. For example, the use of frequency resolution of 0.0005Hz is
more restrictive than is required under BAL-005. Further, the creation of a new term, Net Metering
Error, requires utilization of a meter correction factor that is different and more restrictive than the
net meter value defined and utilized today (which is an estimate). MISO further notes that the meter
error utilized in this standard is referenced and utilized in other BAL standards for which no
modifications are currently proposed. MISO cannot support the addition of terms and requirements
that may contradict or otherwise confuse Registered Entity obligations under other, impacted
Reliability Standards.
No
While MISO agrees that these four entities comprise the four major Interconnections, the term is used
scores of times in other standards. It is beyond the scope of this drafting team to redefine
expectations of other standards.
No
While MISO agrees with the Purpose provided in the standards, it notes that the phrase defined above
is not consistent with the Purpose provided in the version of BAL-001-1 posted for comment.
No
MISO agrees that performance should be evaluated using a 12 month period evaluated on a monthly
basis, but requests clarification that substandard performance in one month would not result in many
months of off-normal performance. More specifically, because the inclusion of one month of offnormal performance apparently would be carried through multiple monthly calculations, the impact of
that one month of off-normal performance would be retained until it “rolls out” of the time frame
required for calculation of the average. Accordingly, a Balancing Authority’s performance could be
impacted for a significantly longer period of time than the time period for which performance was
actually impacted. Additionally, MISO notes that the language utilized in R1 indicates only the
requirement to utilize a 12-month period, but does not prescribe that the time period be a “rolling
twelve month” period as is indicated in the VSL section or as the “most recent consecutive twelve
months” as is indicated in Attachment 1. MISO suggests that all language in the standard regarding
the twelve month period be standardized to ensure that Registered Entity obligations are clear and
unambiguous.
No
The proposed changes in BAL-003 with regard to variable bias (no floor on variable bias) open the
opportunity for gaming R2.
Yes
Yes
Yes
No

While they are not material to the new standard, the A1 criteria are not properly stated. Under A1,
ACE needed to cross zero at least once in every ten minute period of the hour and the total noncrossings had to be less than 10 percent of all periods.
MISO notes the use of cross-references and similar terms among and between reliability standards.
Accordingly, terms and concepts previously utilized in BAL-001-0.1a that have been replaced,
modified, or re-defined in BAL-001-1 may impact other reliability standards such as BAL-003, BAL004, and BAL-005-0.1b. MISO notes that the use of cross-references and similar terms should be
evaluated to ensure consistency amongst the reliability standards and requirements. In particular,
where terms and requirements have been redefined or modified in BAL-001-1, a cross-referenced or
closely related standard or requirement could be impacted by the modification to BAL-001-1. For
example, BAL-005-0.1b references the “ACE equation,” which equation appears to have been replaced
by an equation to calculate Reporting ACE. Additionally, the creation of a new glossary definition could
result in ambiguity regarding required performance outcomes and obligations where a previous
defined term had been used and is maintained in cross-referenced or closely related standards. For
example, several BAL standards refer to and use ACE as a performance standard or requirement. It is
unclear whether this performance obligation remains tied to raw ACE calculations or to an entity’s
Reporting ACE. MISO respectfully suggests that the BARC SDT perform a comprehensive review of
BAL-001-1’s impact on cross-referenced or closely related reliability standards prior to
implementation.
MISO supports this standard generally and, in particular, the concept and use of BAAL in lieu of CPS2.
Individual
Alice Ireland
Xcel Energy
No
The definition of Reporting ACE appears to be overly prescriptive. The WECC has a modified ACE that
is working its way through the process to make it clear that the ACE for compliance purposes would
become the WECC defined ACE, not the NERC defined ACE. The drafting team needs to take this
difference into account and the current draft standard does not account for that modification. The
drafting team also should take this opportunity to include in the definition further clarity related to
concepts such as ACE Diversity Interchange, Dynamic Schedules, Pseudo-ties and Automatic Time
Error Correction.
No
Not all of Texas is in the ERCOT or Texas Interconnection, therefore the proposed change is likely to
cause confusion. As an entity that has a Balancing Authority Area operating in part of the state of
Texas, we can attest to the fact that there is already enough confusion in the industry related to the
difference between electric service in the state of Texas and the Interconnection that operates wholly
within the boundaries of Texas.
No
The purpose does not make sense. In order to make it clearer, end the sentence after the word
“limits.” With this change, it would also be acceptable to add the phrase “during normal operations”
after the word “limits”.
No
The last phrase “to support interconnection frequency” makes the requirement unclear. Does this
language mean that frequency is not allowed to get outside of defined parameters mean that there
has been a violation of the standard by an entity within the interconnection? Please delete that phrase
so the requirement is clear and concise.
No
The last phrase “to support interconnection frequency” makes the requirement unclear. Please delete
that phrase so the requirement is clear and concise. Additionally, the language in the requirement
needs to in some way address the issue of clock minute average that are determined to be invalid do
to issues with the measurement equipment, especially if the measurement equipment has an issue
around the end of a 30 minute exceedance.
No

It is unclear from the language if the required data must be EMS quality or if the data can be from a
data recorder such as PI. The Measure needs to be clear on this issue.
No
Xcel Energy recommends that the Background Document refer to and provide a link to the data and
related evaluations that has been collected over the years of the field trial.
While not a true conflict, it appears that the design of the BAL-001-1 R2 related to RBC and the BAL002-2 R1 are not coordinated. The drafting team should review these two requirements and
determine if there is reason to modify the BAL-002 requirement to more closely match the desire to
operate within a pre-determined range based on frequency under BAL-001-1 R2. Ideally, all four of
the standards under the BARC SDT would be combined into a single standard to reduce the likelihood
of conflicts between them during the compliance process. While separating them may make it easier
to focus on the minute details of one versus the other, there is a large risk that the separation can
cause conflicts based on the interpretation of one versus the interpretation of another. As an example
of the type of conflict that is possible as currently structured, one could argue that Requirement R2 in
BAL-001 supplant Requirement R1 in BAL-002 or is Requirement R1 of BAL-002 the superior
requirement.
Individual
Brett Holland
KCP&L

The proposed BAAL measure in replacement of the current CPS2 removes a performance measure
that is independent of the rest of the interconnection performance. The current CPS2 is based on
interconnection statistical performance and provides an entity with a measure that is an indication of
how well an entity is balanced with energy resources to load obligations. The proposed BAAL measure
is very close in concept to the measure for the current CPS1 and has a similar effect. As the
interconnection frequency moves away from 60 Hz the BAAL boundaries shrink and can shrink to
levels that are lower than metering accuracies inherent in control systems and the normal variations
of ACE that can occur. The current CPS1 ties an entities control performance to rest of the
interconnection as it is a function of actual system frequency. The current CPS2 reflects an entities
independent performance for maintaining an acceptable balance of load to energy resources. It is
important for an entity to have some measure of its own performance apart from the performance of
the interconnection. There may be a reliability need to "tighten" the performance metrics around what
constitutes good and acceptable "balance"of load obligations and energy resources, but it is important
to maintain a metric that reflects an entities performance apart from the rest of the interconnection.
Individual
Laura Lee
Duke Energy
No
Duke Energy agrees with the Balancing Authority ACE Limit definition. Duke Energy does not support
the use of the new term “Reporting ACE” as we are unaware of any issues to date created by the
current defined term in the standard. It is understood that the “instantaneous” value of ACE is the
current scan, as that is the ACE made available to the operator in real-time. The Reporting ACE

definition adds unnecessary confusion and should therefore not be developed. ACE should be
substituted in any instance where “Reporting ACE” is used in these standards. If the drafting team
moves forward with its proposal to use “Reporting ACE”, Duke Energy believes that the Standards and
supporting documentation need to clarify that any reference to “clock-minute ACE” means the clockminute average of the Reporting ACE.
Yes
Though this definition appears appropriate, if the “Texas” Interconnection includes operation of areas
outside of the state of Texas, another name should be considered.
No
The Purpose Statement in the draft differs from what is presented in question 3 and states “To control
Interconnection frequency within defined limits”. The purpose stated in this question is preferable,
with capitalization of the second use of interconnection. Add “in support of Interconnection frequency”
to the proposed Purpose Statement. Additionally, the Background document uses the term
“predefined limits” which is a more accurate description.
Yes
Yes
See comment to question 1 on the use of Reporting ACE.
Yes
Yes
Yes
Yes
The document provides sufficient clarity as to the development of the standard. There is no value
added to the document, however, with the inclusion of the “Historical Significance” section going back
to 1973, A1-A2 Control Performance Criteria, then leading up to 1996 describing the NERC Policy
CPS1, CPS2, and DCS. The SDT simply needs to define CPS1 and CPS2 and their rationale for the
development of the standard. On page 5 of the document, the SDT left out the word “Standard”
between Performance and 2 in the first paragraph under the “Background and Rationale” section.
“Significant hours” is not a good description for the 72 hours per month a BA’s ACE can be outside its
L10 as it is used in the last sentence of the document on page 6. It should be changed to something
along the lines of, “….allows for a Balancing Authority’s ACE value to be unbounded for a specific
amount of time during a calendar month.”
It could be interpreted that the language in R5 of EOP-002-3 conflicts with the CPS1 and BAAL
standards. EOP-002-3 R5 includes the sentences, “The Balancing Authority shall not unilaterally
adjust generation in an attempt to return Interconnection frequency to normal beyond that supplied
through frequency bias action and Interchange Schedule changes. Such unilateral adjustment may
overload transmission facilities.” As operation in support of Interconnection frequency under CPS1 and
BAAL allows for support beyond that supplied by frequency bias action, Duke Energy believes that the
sentences should be taken out of EOP-002-3 R5, which were never intended to be applicable to the
deficient Balancing Authority for which the standard applies. Conforming changes will also need to be
made to EOP-002-3 R6 which references “Control Performance and Disturbance Control Standards”. It
could be interpreted from the language in R6 of EOP-002-3, that a Balancing Authority is considered
in an emergency condition and should be implementing its emergency plan if it is not capable of
complying at any time to the CPS1, CPS2, BAAL, or DCS measures. In a multiple-BA Interconnection,
the bounds of CPS1 and BAAL represent each BA’s share of responsibility in maintaining frequency
within defined bounds - to the extent that Interconnection frequency remains within acceptable limits,
non-compliance in a general sense is more of an equity concern, than a reliability issue rising to the
level requiring actions up to an including the shedding of firm load to remain compliant. Under what
circumstances should the Balancing Authority shed firm load as a last resort to ensure that it remains
compliant to the “Control Performance and Disturbance Control Standards”?
Duke Energy does not believe that the Applicability section of the Standard should contain or clarify

requirements of entities to the extent presented in the draft BAL-001-1. As the current definition of
Overlap Regulation Service states “A method of providing regulation service in which the Balancing
Authority providing the regulation service incorporates another Balancing Authority’s actual
interchange, frequency response, and schedules into providing Balancing Authority’s AGC/ACE
equation”, Duke Energy would propose that Applicability should be assigned to “Balancing Authority
not receiving Overlap Regulation Service”. There appear to be incorrect references in the VRF/VSL
document. The justification for R1 references BAL-003-1 for Guideline 2 instead of BAL-001-1. The
justification for R2 also references BAL-003-1 for Guideline The Compliance Enforcement Authority
Section language is not the same as that specified in the Background Information for Quality Reviews
dated February 2012.

Comment Form

Project 2010-14.1 Balancing Authority Reliability-based Control
BAL-001-1 í Real Power Balancing Control Performance

Please do not use this form to submit comments on the proposed revisions to BAL-001-1 Real Power
Balancing Control Performance. Comments must be submitted on the electronic comment form by 8
p.m. July 3, 2012. If you have questions please contact Darrel Richardson (email) or by telephone at
(609) 613-1848.
BAL-001-1 Real Power Balancing Control Performance
Background Information:

Control Performance Standard 1 (CPS1) has been retained, and details for calculating CPS1 are included
in Attachment 1. Calculation of Reporting Area Control Error (Reporting ACE) has been clarified, and
details for calculating Reporting ACE are also included in Attachment 1. The Balancing Authority ACE
Limit (BAAL), an interconnection frequency and Balancing Authority ACE measurement, is included in
this standard as Requirement 2 and replaces Control Performance Standard 2 (CPS2). Details for the
calculation of BAAL are included in Attachment 2.
CPS2 was not designed to address Interconnection frequency. Currently, it measures the ability of a
Balancing Authority to maintain its average ACE within a fixed limit of plus or minus a MW value called
L10. To be compliant, a Balancing Authority must demonstrate its average ACE value during a
consecutive ten minute period was within the L10 bound 90 percent of all 10 minute periods over a
one month period. While this standard does require the Balancing Authority to correct its ACE to not
exceed specific bounds, it fails to recognize Interconnection frequency.
BAAL is defined by two equations, BAAL low and BAAL high. BAAL low is for Interconnection frequency
values less than 60 hertz and BAAL high is for Interconnection frequency values greater than 60 hertz.
BAAL values for each Balancing Authority are dynamic and change as Interconnection frequency
changes. For example, as Interconnection frequency moves from 60 hertz, the ACE limit for each
Balancing Authority becomes more restrictive. The BAAL provides each Balancing Authority a dynamic
ACE limit that is a function of Interconnection frequency.
As a proof of concept for the proposed BAAL standard, a BAAL field trial was approved by the NERC
Standards Committee and the Operating Committee. Currently there are 13 Balancing Authorities
participating in the Eastern Interconnection, 26 Balancing Authorities participating in the Western
Interconnection, the ERCOT Balancing Authority, and Quebec. Reliability Coordinators for all
interconnections continue to monitor the performance of those participating Balancing Authorities and

provide information to support monthly analysis of the BAAL field trial. As of the end of September
2011, no reliability issues with the BAAL field trial have been identified by any Reliability Coordinator.
You do not have to answer all questions. Enter All Comments in Simple Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. The BARC SDT has developed two new terms to be used with this standard.
Balancing Authority ACE Limit (BAAL):
The limit beyond which a Balancing Authority contributes more than its share of
Interconnection frequency control reliability risk. This definition applies to a high limit
(BAALHigh) and a low limit (BAALLow).
Reporting ACE:
The scan rate values of a Balancing Authority’s Area Control Error (ACE) measured in
MW as defined in BAL-001 which includes the difference between the Balancing
Authority’s actual interchange and its scheduled interchange plus its frequency bias
obligation plus any known meter error.
Do you agree with the proposed definitions in this standard? If not, please explain in the
comment area below.
Yes
No
Comments:
2. The SDT has modified the definition for the term Interconnection. The new definition
is shown below in redline to show the changes proposed.

Interconnection:
When capitalized, any one of the fourthree major electric system networks in North
America: Eastern, Western, Texas and QuebecERCOT.
Do you agree with this new definition for Interconnection? If not, please explain in the comment
area below.
Yes
No
Comments:
3. The proposed Purpose Statement for the draft standard is:

BAL-001-1 Real Power Balancing Control Performance
Comment Form

2

To control Interconnection frequency within defined limits in support of interconnection
frequency.
Do you agree with this purpose statement? If not, please explain in the comment area below.
Yes
No
Comments:
4. The BARC SDT has developed Requirement R1 to measure how well a Balancing Authority is able
to control its generation and load management programs, as measured by its Area Control Error
(ACE), to supports its Interconnection’s frequency over a rolling one year period.
R1. Each Balancing Authority shall operate such that the Balancing Authority’s Control
Performance Standard 1 (CPS1), as calculated in Attachment 1, is greater than or equal to 100%
for the applicable Interconnection in which it operates for each 12 month period, evaluated
monthly, to support interconnection frequency.
Do you agree with this Requirement? If not, please explain in the comment area below.
Yes
No
Comments:
5. The BARC SDT has developed Requirement R2 to enhance the reliability of each Interconnection
by maintaining frequency within predefined limits under all conditions.
R2. Each Balancing Authority shall operate such that its clock-minute average of Reporting ACE
does not exceed for more than 30 consecutive clock-minutes its clock-minute Balancing
Authority ACE Limit (BAAL), as calculated in Attachment 2, for the applicable Interconnection in
which it operates to support interconnection frequency.
Do you agree with this Requirement? If not, please explain in the comment area below.
Yes
No
Comments: In HQT’s fielt trial, frequency limits were defined from 59.9 Hz to 60.1Hz. The
proposed methodology in Appendix 2 does not reflect those values since the 3*epsilon
methodology leads to 59.937 Hz to 60.063 Hz frequency limits.
6. The BARC SDT has developed VRFs for the proposed Requirements within this standard. Do you
agree that these VRFs are appropriately set? If not, please explain in the comment area below.
Yes
No

BAL-001-1 Real Power Balancing Control Performance
Comment Form

3

Comments:
7. The BARC SDT has developed Measures for the proposed Requirements within this standard. Do
you agree with the proposed Measures in this standard? If not, please explain in the comment
area.
Yes
No
Comments:
8. The BARC SDT has developed VSLs for the proposed Requirements within this standard. Do you
agree with these VSLs? If not, please explain in the comment area.
Yes
No
Comments:
9. The BARC SDT has developed a document “BAL-001-1 Real Power Balancing Control Standard
Background Document” which provides information behind the development of the standard.
Do you agree that this new document provides sufficient clarity as to the development of the
standard? If not, please explain in the comment area.
Yes
No
Comments:
10. If you are aware of any conflicts between the proposed standard and any regulatory function,
rule order, tariff, rate schedule, legislative requirement, or agreement please identify the conflict
here.
Comments:
11.

Do you have any other comment on BAL-001-1, not expressed in the questions above, for the
BARC SDT?
Comments:

BAL-001-1 Real Power Balancing Control Performance
Comment Form

4

Comment Form

Project 2010-14.1 Balancing Authority Reliability-based Control
BAL-001-1 í Real Power Balancing Control Performance

Please do not use this form to submit comments on the proposed revisions to BAL-001-1 Real Power
Balancing Control Performance. Comments must be submitted on the electronic comment form by 8
p.m. July 3, 2012. If you have questions please contact Darrel Richardson (email) or by telephone at
(609) 613-1848.
BAL-001-1 Real Power Balancing Control Performance
Background Information:

Control Performance Standard 1 (CPS1) has been retained, and details for calculating CPS1 are included
in Attachment 1. Calculation of Reporting Area Control Error (Reporting ACE) has been clarified, and
details for calculating Reporting ACE are also included in Attachment 1. The Balancing Authority ACE
Limit (BAAL), an interconnection frequency and Balancing Authority ACE measurement, is included in
this standard as Requirement 2 and replaces Control Performance Standard 2 (CPS2). Details for the
calculation of BAAL are included in Attachment 2.
CPS2 was not designed to address Interconnection frequency. Currently, it measures the ability of a
Balancing Authority to maintain its average ACE within a fixed limit of plus or minus a MW value called
L10. To be compliant, a Balancing Authority must demonstrate its average ACE value during a
consecutive ten minute period was within the L10 bound 90 percent of all 10 minute periods over a
one month period. While this standard does require the Balancing Authority to correct its ACE to not
exceed specific bounds, it fails to recognize Interconnection frequency.
BAAL is defined by two equations, BAAL low and BAAL high. BAAL low is for Interconnection frequency
values less than 60 hertz and BAAL high is for Interconnection frequency values greater than 60 hertz.
BAAL values for each Balancing Authority are dynamic and change as Interconnection frequency
changes. For example, as Interconnection frequency moves from 60 hertz, the ACE limit for each
Balancing Authority becomes more restrictive. The BAAL provides each Balancing Authority a dynamic
ACE limit that is a function of Interconnection frequency.
As a proof of concept for the proposed BAAL standard, a BAAL field trial was approved by the NERC
Standards Committee and the Operating Committee. Currently there are 13 Balancing Authorities
participating in the Eastern Interconnection, 26 Balancing Authorities participating in the Western
Interconnection, the ERCOT Balancing Authority, and Quebec. Reliability Coordinators for all
interconnections continue to monitor the performance of those participating Balancing Authorities and

provide information to support monthly analysis of the BAAL field trial. As of the end of September
2011, no reliability issues with the BAAL field trial have been identified by any Reliability Coordinator.
You do not have to answer all questions. Enter All Comments in Simple Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. The BARC SDT has developed two new terms to be used with this standard.
Balancing Authority ACE Limit (BAAL):
The limit beyond which a Balancing Authority contributes more than its share of
Interconnection frequency control reliability risk. This definition applies to a high limit
(BAALHigh) and a low limit (BAALLow).
Reporting ACE:
The scan rate values of a Balancing Authority’s Area Control Error (ACE) measured in
MW as defined in BAL-001 which includes the difference between the Balancing
Authority’s actual interchange and its scheduled interchange plus its frequency bias
obligation plus any known meter error.
Do you agree with the proposed definitions in this standard? If not, please explain in the
comment area below.
Yes
No
Comments:
In attachment 1, the FA (Actual Frequency) term is defined and indicates a resolution of ±0.0005 Hz.
This should be changed to align with the BAL-005-0.1b R17 that indicates a frequency resolution ч
0.001 Hz.
Additionally, the acronym “ACE” is defined in the Reporting ACE definition but not in the BAAL
definition. It should be defined at each usage or at none.
2. The SDT has modified the definition for the term Interconnection. The new definition
is shown below in redline to show the changes proposed.

Interconnection:
When capitalized, any one of the fourthree major electric system networks in North
America: Eastern, Western, Texas and QuebecERCOT.

BAL-001-1 Real Power Balancing Control Performance
Comment Form

2

Do you agree with this new definition for Interconnection? If not, please explain in the comment
area below.
Yes
No
Comments:
3. The proposed Purpose Statement for the draft standard is:
To control Interconnection frequency within defined limits in support of interconnection
frequency.
Do you agree with this purpose statement? If not, please explain in the comment area below.
Yes
No
Comments:
4. The BARC SDT has developed Requirement R1 to measure how well a Balancing Authority is able
to control its generation and load management programs, as measured by its Area Control Error
(ACE), to supports its Interconnection’s frequency over a rolling one year period.
R1. Each Balancing Authority shall operate such that the Balancing Authority’s Control
Performance Standard 1 (CPS1), as calculated in Attachment 1, is greater than or equal to 100%
for the applicable Interconnection in which it operates for each 12 month period, evaluated
monthly, to support interconnection frequency.
Do you agree with this Requirement? If not, please explain in the comment area below.
Yes
No
Comments:
Although Manitoba Hydro agrees with this Requirement, we suggest the following clarifications to
the Requirement wording. The words ‘as calculated in Attachment 1’ should be replaced with
‘calculated in accordance with Attachment 1’ for clarity. The reference to ‘it’ should specify the
Balancing Authority for clarity.
5. The BARC SDT has developed Requirement R2 to enhance the reliability of each Interconnection
by maintaining frequency within predefined limits under all conditions.
R2. Each Balancing Authority shall operate such that its clock-minute average of Reporting ACE
does not exceed for more than 30 consecutive clock-minutes its clock-minute Balancing
Authority ACE Limit (BAAL), as calculated in Attachment 2, for the applicable Interconnection in
which it operates to support interconnection frequency.

BAL-001-1 Real Power Balancing Control Performance
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3

Do you agree with this Requirement? If not, please explain in the comment area below.
Yes
No
Comments:
The reference to ‘it’ should specify the Balancing Authority for clarity.
6. The BARC SDT has developed VRFs for the proposed Requirements within this standard. Do you
agree that these VRFs are appropriately set? If not, please explain in the comment area below.
Yes
No
Comments:
7. The BARC SDT has developed Measures for the proposed Requirements within this standard. Do
you agree with the proposed Measures in this standard? If not, please explain in the comment
area.
Yes
No
Comments:
8. The BARC SDT has developed VSLs for the proposed Requirements within this standard. Do you
agree with these VSLs? If not, please explain in the comment area.
Yes
No
Comments:
9. The BARC SDT has developed a document “BAL-001-1 Real Power Balancing Control Standard
Background Document” which provides information behind the development of the standard.
Do you agree that this new document provides sufficient clarity as to the development of the
standard? If not, please explain in the comment area.
Yes
No
Comments:
10. If you are aware of any conflicts between the proposed standard and any regulatory function,
rule order, tariff, rate schedule, legislative requirement, or agreement please identify the conflict
here.

BAL-001-1 Real Power Balancing Control Performance
Comment Form

4

Comments:
In attachment 1, the FA (Actual Frequency) term is defined and indicates a resolution of ±0.0005 Hz.
This should be changed to align with the BAL-005-0.1b R17 that indicates a frequency resolution ч
0.001 Hz.
11. Do you have any other comment on BAL-001-1, not expressed in the questions above, for the
BARC SDT?
Comments:
Under Applicability Section 4.1.1, the term “CPS1” is used but the acronym is not defined until R1.
It should be defined at the first use.
Under the Effective Date Section, the effective date language has a few issues in its drafting. It
would be clearer to use the word ‘following’ as opposed to the word ‘beyond’ (and this would also
be more consistent with the drafting of similar sections in other standards). The words ‘the
standard becomes effective’ in the third line are not needed. The words ‘made pursuant to the
laws applicable to such ERO governmental authorities’ may not be appropriate. It’s not the laws
applicable to the governmental authorities that are relevant, but the laws applicable to the entity
itself. We would suggest wording like ‘or as otherwise made effective pursuant to the laws
applicable to the Balancing Authority’. Also, ERO is not defined.

BAL-001-1 Real Power Balancing Control Performance
Comment Form

5

Comment Form

Project 2010-14.1 Balancing Authority Reliability-based Control
BAL-001-1 í Real Power Balancing Control Performance

Please do not use this form to submit comments on the proposed revisions to BAL-001-1 Real Power
Balancing Control Performance. Comments must be submitted on the electronic comment form by 8
p.m. July 3, 2012. If you have questions please contact Darrel Richardson (email) or by telephone at
(609) 613-1848.
BAL-001-1 Real Power Balancing Control Performance
Background Information:

Control Performance Standard 1 (CPS1) has been retained, and details for calculating CPS1 are included
in Attachment 1. Calculation of Reporting Area Control Error (Reporting ACE) has been clarified, and
details for calculating Reporting ACE are also included in Attachment 1. The Balancing Authority ACE
Limit (BAAL), an interconnection frequency and Balancing Authority ACE measurement, is included in
this standard as Requirement 2 and replaces Control Performance Standard 2 (CPS2). Details for the
calculation of BAAL are included in Attachment 2.
CPS2 was not designed to address Interconnection frequency. Currently, it measures the ability of a
Balancing Authority to maintain its average ACE within a fixed limit of plus or minus a MW value called
L10. To be compliant, a Balancing Authority must demonstrate its average ACE value during a
consecutive ten minute period was within the L10 bound 90 percent of all 10 minute periods over a
one month period. While this standard does require the Balancing Authority to correct its ACE to not
exceed specific bounds, it fails to recognize Interconnection frequency.
BAAL is defined by two equations, BAAL low and BAAL high. BAAL low is for Interconnection frequency
values less than 60 hertz and BAAL high is for Interconnection frequency values greater than 60 hertz.
BAAL values for each Balancing Authority are dynamic and change as Interconnection frequency
changes. For example, as Interconnection frequency moves from 60 hertz, the ACE limit for each
Balancing Authority becomes more restrictive. The BAAL provides each Balancing Authority a dynamic
ACE limit that is a function of Interconnection frequency.
As a proof of concept for the proposed BAAL standard, a BAAL field trial was approved by the NERC
Standards Committee and the Operating Committee. Currently there are 13 Balancing Authorities
participating in the Eastern Interconnection, 26 Balancing Authorities participating in the Western
Interconnection, the ERCOT Balancing Authority, and Quebec. Reliability Coordinators for all
interconnections continue to monitor the performance of those participating Balancing Authorities and

provide information to support monthly analysis of the BAAL field trial. As of the end of September
2011, no reliability issues with the BAAL field trial have been identified by any Reliability Coordinator.
You do not have to answer all questions. Enter All Comments in Simple Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. The BARC SDT has developed two new terms to be used with this standard.
Balancing Authority ACE Limit (BAAL):
The limit beyond which a Balancing Authority contributes more than its share of
Interconnection frequency control reliability risk. This definition applies to a high limit
(BAALHigh) and a low limit (BAALLow).
Reporting ACE:
The scan rate values of a Balancing Authority’s Area Control Error (ACE) measured in
MW as defined in BAL-001 which includes the difference between the Balancing
Authority’s actual interchange and its scheduled interchange plus its frequency bias
obligation plus any known meter error.
Do you agree with the proposed definitions in this standard? If not, please explain in the
comment area below.
Yes
No
Comments:
2. The SDT has modified the definition for the term Interconnection. The new definition
is shown below in redline to show the changes proposed.

Interconnection:
When capitalized, any one of the fourthree major electric system networks in North
America: Eastern, Western, Texas and QuebecERCOT.
Do you agree with this new definition for Interconnection? If not, please explain in the comment
area below.
Yes
No
Comments:
3. The proposed Purpose Statement for the draft standard is:

BAL-001-1 Real Power Balancing Control Performance
Comment Form

2

To control Interconnection frequency within defined limits in support of interconnection
frequency.
Do you agree with this purpose statement? If not, please explain in the comment area below.
Yes
No
Comments: Delete “in support of interconnection frequency”.
4. The BARC SDT has developed Requirement R1 to measure how well a Balancing Authority is able
to control its generation and load management programs, as measured by its Area Control Error
(ACE), to supports its Interconnection’s frequency over a rolling one year period.
R1. Each Balancing Authority shall operate such that the Balancing Authority’s Control
Performance Standard 1 (CPS1), as calculated in Attachment 1, is greater than or equal to 100%
for the applicable Interconnection in which it operates for each 12 month period, evaluated
monthly, to support interconnection frequency.
Do you agree with this Requirement? If not, please explain in the comment area below.
Yes
No
Comments: This is an existing requirement and was not modified by the standard drafting team.
5. The BARC SDT has developed Requirement R2 to enhance the reliability of each Interconnection
by maintaining frequency within predefined limits under all conditions.
R2. Each Balancing Authority shall operate such that its clock-minute average of Reporting ACE
does not exceed for more than 30 consecutive clock-minutes its clock-minute Balancing
Authority ACE Limit (BAAL), as calculated in Attachment 2, for the applicable Interconnection in
which it operates to support interconnection frequency.
Do you agree with this Requirement? If not, please explain in the comment area below.
Yes
No
Comments: The SERC OC Standards Review Group is concerned that the reliability impact of
violating this requirement is proportional to the size of the balancing authority. For example,
PJM, at a size of over 100,000 MW has a much more impact on reliability than SEPA, at less than
2000 MW. We do not understand how to apply VRFs consistently. This may require splitting into
multiple VRFs considering the size of the BA.
6. The BARC SDT has developed VRFs for the proposed Requirements within this standard. Do you
agree that these VRFs are appropriately set? If not, please explain in the comment area below.
Yes

BAL-001-1 Real Power Balancing Control Performance
Comment Form

3

No
Comments: See comments to No. 5 above.
7. The BARC SDT has developed Measures for the proposed Requirements within this standard. Do
you agree with the proposed Measures in this standard? If not, please explain in the comment
area.
Yes
No
Comments:
8. The BARC SDT has developed VSLs for the proposed Requirements within this standard. Do you
agree with these VSLs? If not, please explain in the comment area.
Yes
No
Comments: Perhaps VSLs could be graded by the size of the entity in lieu of having multiple
VRFs.
9. The BARC SDT has developed a document “BAL-001-1 Real Power Balancing Control Standard
Background Document” which provides information behind the development of the standard.
Do you agree that this new document provides sufficient clarity as to the development of the
standard? If not, please explain in the comment area.
Yes
No
Comments:
10. If you are aware of any conflicts between the proposed standard and any regulatory function,
rule order, tariff, rate schedule, legislative requirement, or agreement please identify the conflict
here.
Comments: No
11. Do you have any other comment on BAL-001-1, not expressed in the questions above, for the
BARC SDT?
Comments: Should the standard include reporting requirements to the RRO? On Attachment 1,
the Interconnection names need to be revised to agree with the Interconnection as stated earlier
in question 2.

BAL-001-1 Real Power Balancing Control Performance
Comment Form

4

“The comments expressed herein represent a consensus of the views of the above named members of
the SERC OC Standards Review group only and should not be construed as the position of SERC
Reliability Corporation, its board or its officers.”

Members participating in the development of comments:
Jeff Harrison
Stuart Goza
Gerry Beckerle
Cindy martin
Andy Burch
Larry Akens
Devan Hoke
Wayne Van Liere
Kelly Casteel
John Jackson
Brad Gordon
Randi Heise
Dan Roethemeyer
Jim Case
Bill Thigpen
Jake Miller
Steve Corbin
Ena Agbedia
Ron Carlsen
Vicky Budreau
Shammara Hasty
Melinda Montgomery
Terry Coggins
J.T. Wood
Antonio Grayson
John Troha

[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]
[email protected]

BAL-001-1 Real Power Balancing Control Performance
Comment Form

5

Consideration of Comments

Phase 1 of Balancing Authority Reliability-based Controls: Reserves
BAL-001-1

TheBalancingAuthorityReliabilityͲbasedControls:ReservesDraftingTeamthanksallcommenterswho
submittedcommentsontheproposedrevisionstoBALͲ001Ͳ1RealPowerBalancingControl
Performance.Thesestandardswerepostedfora30ͲdaypubliccommentperiodfromJune4,2012
throughJuly3,2012.Stakeholderswereaskedtoprovidefeedbackonthestandardsandassociated
documentsthroughaspecialelectroniccommentform.Therewere38setsofcomments,including
commentsfromapproximately136differentpeoplefromapproximately85companiesrepresenting9
ofthe10IndustrySegmentsasshowninthetableonthefollowingpages.

Basedonindustrycommentsthedraftingteammadethefollowingclarifyingmodificationstothe
proposedstandardandassociateddocuments.
x CreatedadefinitionforRegulationReserveSharingGroupandRegulationReserveSharing
GroupreportingACE.
x RemovedtheequationforcalculatingReportingACEfromtheattachmentandaddedittothe
definition.
x Modifiedtheapplicabilitysectiontoprovideadditionalclarityandremoveanyambiguity.
x MademinorclarifyingmodificationstoRequirementR1andRequirementR2.
x MademinorclarifyingmodificationstotheVSLsforRequirementR1andRequirementR2.
x ModifiedtheBackgroundDocumenttoprovideadditionalclarity.

Therewereacoupleofminorityissuesthattheteamwasunabletoresolve,includingthefollowing:
x SeveralstakeholdersfeltthatmodifyingthedefinitionforInterconnectionwasoutsidethe
scopeofthedraftingteam’sSAR.ThedraftingteamdisagreeswithyouregardingtheSAR.The
SARstatesthatthedraftingteamistoaddressthedirectivesfromFERCOrder693.Oneof
thesedirectiveswastoestablishacontinentwidecontingencyreservepolicy.SinceQuebecis
partofthecontinentthereforethetermInterconnectionshouldbecorrected.
x ManystakeholdersfeltthatusingBAAlhadcausedincreasedinadvertentflowsand
transmissionissues.Thedraftingteamstatedthattheyhadnotseenanyissuesthatyouare
describingoccurduringthefieldtrialthatcanbedirectlyattributabletotheuseofBAAL.BAAL
wasdesignedtoprovideforbettercontrolbyallowingpowerflowsthatdonothavea
detrimentaleffectonreliabilitybutrestrictthosethatdohaveadetrimentaleffecton
reliability.
x Afewstakeholderswantedtoaddtheterm“steadyͲstate”tothepurposestatement.The
draftingteamexplainedthatfrequencyisalwaysdynamic.Thedraftingteambelievesthat
addingthetermsteadyͲstatewouldrequireadditionalclarityastothemeaningofsteadyͲstate
andcouldcreateambiguity.

x

x

Acoupleofstakeholdersthoughtthatreferencinganattachmentintherequirementwould
createrequirementswithintheattachment.Thedraftingteamexplainedthattheattachment
wasnotcreatinganyadditionalrequirements.Theattachmentonlyprovidesthecalculation
methodology.Thedraftingteambelievesthattherequirementsshouldonlystatewhatan
entityissupposedtodo,nothowtocalculatesomething.
AcoupleofstakeholderswereconcernedthatasmallBAsoperationcouldbemorerestrictive
underBAAL.Thedraftingteamstatedthattheywereawareoftheconcernidentified.
However,thedraftingteamisattemptingtodevelopastandardthatwouldbeapplicabletothe
entirecontinentanddoesnotknowofanymethodtodistinguishbetweenlargerandsmaller
BAs.


Allcommentssubmittedmaybereviewedintheiroriginalformatonthestandard’sprojectpage:

http://www.nerc.com/filez/standards/Project2010Ͳ14.1_Phase_1_of_Balancing_Authority_RBC.html

Ifyoufeelthatyourcommenthasbeenoverlooked,pleaseletusknowimmediately.Ourgoalistogive
everycommentseriousconsiderationinthisprocess!Ifyoufeeltherehasbeenanerrororomission,
youcancontacttheVicePresidentandDirectorofStandards,MarkLauby,at404Ͳ446Ͳ9723orat
[email protected].Inaddition,thereisaNERCReliabilityStandardsAppealsProcess.1





1

TheappealsprocessisintheStandardProcessesManual:http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf



Consideration of Comments: Project 2010-14.1 BAL-001-1

2

IndextoQuestions,Comments,andResponses

1.

TheBARCSDThasdevelopedtwonewtermstobeusedwiththisstandard.BalancingAuthority
ACELimit(BAAL):ThelimitbeyondwhichaBalancingAuthoritycontributesmorethanitsshareof
Interconnectionfrequencycontrolreliabilityrisk.Thisdefinitionappliestoahighlimit(BAALHigh)
andalowlimit(BAALLow).ReportingACE:ThescanratevaluesofaBalancingAuthority’sArea
ControlError(ACE)measuredinMWasdefinedinBALͲ001whichincludesthedifferencebetween
theBalancingAuthority’sactualinterchangeanditsscheduledinterchangeplusitsfrequencybias
obligationplusanyknownmetererror.Doyouagreewiththeproposeddefinitionsinthis
standard?Ifnot,pleaseexplaininthecommentareabelow. ..................................... 11

2.

TheSDThasmodifiedthedefinitionforthetermInterconnection.Pleaseviewthenewdefinition
showninredlineontheUnofficialWordversionpostedontheprojectpagewhichshowsthe
changesproposed.http://www.nerc.com/filez/standards/Project2010Ͳ
14.1_Phase_1_of_Balancing_Authority_RBC.htmlInterconnection:Whencapitalized,anyoneof
thefourmajorelectricsystemnetworksinNorthAmerica:Eastern,Western,TexasandQuebec.
DoyouagreewiththisnewdefinitionforInterconnection?Ifnot,pleaseexplaininthecomment
areabelow. ..................................................................................................... 23

3.TheproposedPurposeStatementforthedraftstandardis:TocontrolInterconnectionfrequency
withindefinedlimitsinsupportofinterconnectionfrequency.Doyouagreewiththispurpose
statement?Ifnot,pleaseexplaininthecommentareabelow. ................................... 28
4.TheBARCSDThasdevelopedRequirementR1tomeasurehowwellaBalancingAuthorityisableto
controlitsgenerationandloadmanagementprograms,asmeasuredbyitsAreaControlError
(ACE),tosupportsitsInterconnection’sfrequencyoverarollingoneyearperiod.R1.Each
BalancingAuthorityshalloperatesuchthattheBalancingAuthority’sControlPerformance
Standard1(CPS1),ascalculatedinAttachment1,isgreaterthanorequalto100%forthe
applicableInterconnectioninwhichitoperatesforeach12monthperiod,evaluatedmonthly,to
supportinterconnectionfrequency.DoyouagreewiththisRequirement?Ifnot,pleaseexplainin
thecommentareabelow. .................................................................................. 35
5.TheBARCSDThasdevelopedRequirementR2toenhancethereliabilityofeachInterconnectionby
maintainingfrequencywithinpredefinedlimitsunderallconditions.R2.EachBalancingAuthority
shalloperatesuchthatitsclockͲminuteaverageofReportingACEdoesnotexceedformorethan
30consecutiveclockͲminutesitsclockͲminuteBalancingAuthorityACELimit(BAAL),ascalculated
inAttachment2,fortheapplicableInterconnectioninwhichitoperatestosupport
interconnectionfrequency..DoyouagreewiththisRequirement?Ifnot,pleaseexplaininthe
commentareabelow. ....................................................................................... 43

Consideration of Comments: Project 2010-14.1 BAL-001-1

3

6.TheBARCSDThasdevelopedVRFsfortheproposedRequirementswithinthisstandard.Doyou
agreethattheseVRFsareappropriatelyset?Ifnot,pleaseexplaininthecommentareabelow.
57

7.TheBARCSDThasdevelopedMeasuresfortheproposedRequirementswithinthisstandard.Do
youagreewiththeproposedMeasuresinthisstandard?Ifnot,pleaseexplaininthecomment
area. .............................................................................................................. 61
8.TheBARCSDThasdevelopedVSLsfortheproposedRequirementswithinthisstandard.Doyou
agreewiththeseVSLs?Ifnot,pleaseexplaininthecommentarea............................. 65
9.TheBARCSDThasdevelopedadocument“BALͲ001Ͳ1RealPowerBalancingControlStandard
BackgroundDocument”whichprovidesinformationbehindthedevelopmentofthestandard.Do
youagreethatthisnewdocumentprovidessufficientclarityastothedevelopmentofthe
standard?Ifnot,pleaseexplaininthecommentarea............................................... 69
10.Ifyouareawareofanyconflictsbetweentheproposedstandardandanyregulatoryfunction,rule
order,tariff,rateschedule,legislativerequirement,oragreementpleaseidentifytheconflicthere.
77

11.DoyouhaveanyothercommentonBALͲ001Ͳ1,notexpressedinthequestionsabove,forthe
BARCSDT? ...................................................................................................... 84

Consideration of Comments: Project 2010-14.1 BAL-001-1

4

TerryBilke

IESO

SPP

3. Ben Li

4. Charles Yeung

Organization

ISO'sStandardsReviewCommittee
2

Central Electric Power Cooperative

KAMO Electric Cooperative

2.

2

2

Region

SERC

SERC

Segment
Selection
1, 3

1, 3

AssociatedElectricCooperativeInc,
JRO00088

Additional Organization

SPP

NPCC

ERCOT 2

RFC

1.

Additional Member

DavidDockery

ERCOT

2. Steve Meyers

Group

PJM

2.



Group

Commenter

Additional Member Additional Organization Region Segment Selection

1. Al DiCaprio

1.

Group/Individual

TheIndustrySegmentsare:
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

X



1



X

2

X



3





4

X



5

X



6





7





8

RegisteredBallotBodySegment





9





10

SWTC

4. John Shaver

WECC 1

MRONSRF

XCEL

BEPC

LES

MGE

RPU

MEC

MISO

OTP

MPW

NPPD

GRE

MPC

6. ALICE IRELAND

7. DAVE RUDOLPH

8. ERIC RUSKAMP

9. JOE DEPOORTER

10. SCOTT NICKELS

11. TERRY HARBOUR

12. MARIE KNOX

13. LEE KITTELSON

14. SCOTT BOS

15. TONY EDDLEMAN

16. MIKE BRYTOWSKI

17. DAN INMAN

1, 3, 5, 6

1, 3, 5, 6

1, 3, 5

1, 3, 5, 6

1, 3, 4, 5

2

5, 6, 1, 3

4

3, 4, 5, 6

1, 3, 5, 6

1, 3, 5, 6

1, 3, 5, 6

4

1, 2

1, 3

1, 3

1, 3

1, 3

NortheastPowerCoordinatingCouncil

MRO

MRO

MRO

MRO

MRO

MRO

MRO

MRO

MRO

MRO

MRO

MRO

MRO

3, 4, 5, 6

1

1, 3, 5, 6

Consideration of Comments: Project 2010-14.1 BAL-001-1

GuyZito

ALTW

5. KEN GOLDSMITH

Group

WAPA

4. JODI JENSON

MRO

MRO

WPS

3. TOM WEBB

MRO
MRO

OPPD

2. CHUCK LAWRENCE ATC

1. MAHMOOD SAFI

5.



1

Additional Member Additional Organization Region Segment Selection

WILLSMITH

AEPCO

1

WECC 4, 5

Sunflower Electric Power Corporation SPP

3. John Shaver

RFC

2. Megan Wagner

Group

SERC

SERC

SERC

Region Segment Selection

Hoosier Energy

Additional Organization

JasonMarshall

1. Bob Solomon

4.



Group

Sho-Me Power Electric Cooperative

6.

Additional Member

N.W. Electric Power Cooperative, Inc.

5.

SERC

Organization

ACESPowerMarketingStandards
Collaborators

Northeast Missouri Electric Power Cooperative

4.

3.



M & A Electric Power Cooperative

Commenter

3.

Group/Individual



X



1



X



2



X



3



X



4



X



5



X

X

6

6







7







8

RegisteredBallotBodySegment







9

X





10

Hydro-Quebec TransEnergie

3. Sylvain Clermont

NPCC 1

NPCC 2

NPCC 10

Northeast Power Coordinating Council

ISO - New England

Northeast Power Coordinating Council

Consolidated Edison Co. of New York, Inc. NPCC 3

New Brunswick System Operator

Orange and Rockland Utilities

The United Illuminating Company

Utility Services

New Brunswick Power Transmission

New York Power Authority

New York Power Authority

Hydro One Networks Inc.

Hydro-Quebec TransEnergie

Ontario Power Generation, Inc,

7. Lee Pedowicz

8. Kathleen Goodman

9. Gerry Dunbar

10. Peter Yost

11. Donald Weaver

12. Ben Wu

13. Robert Pellegrini

14. Brian Robinson

15. Randy MacDonald

16. Bruce Metruck

17. Wayne Sipperly

18. David Kiguel

19. Si-Truc Phan

20. David Ramkalawan

National Grid

24. Michael Schiavone

SERCOCStandardsReviewGroup(see
emaillist)

NPCC 1

AECI

Southern

EEI

2. Jeff Harrison

3. Cindy Martin

4. Andy Burch

SERC

SERC

SERC

SERC

5

1, 5

1, 3, 5, 6

1, 3

Consideration of Comments: Project 2010-14.1 BAL-001-1

Ameren

1. Gerald Beckerle

Additional Member Additional Organization Region Segment Selection

StuartGoza

National Grid

23. Michael Jones

Group

NPCC 2

Independent Electricity System Operator

22. Carmen Agavriloai
NPCC 1

NPCC 5

21. Silvia Parada Mitchell NextEra Energy, LLC

NPCC 5

NPCC 1

NPCC 1

NPCC 5

NPCC 6

NPCC 9

NPCC 8

NPCC 1

NPCC 1

NPCC 2

NPCC 10

NPCC 2

NPCC 10

NPCC 1

Northeast Utilities

6. Michael Lombardi

NPCC 5

Dominion Resources Services, Inc.

5. Mike Garton

6.



New York Independent System Operator

2. Greg Campoli

Region Segment Selection

Organization

4. Chris de Graffenried Consolidated Edison Co. of New York, Inc. NPCC 1

New York State Reliability Council, LLC

Additional Organization

Commenter

1. Alan Adamson

Additional Member

Group/Individual

X

1



2

X

3



4

X

5



6

7



7



8

RegisteredBallotBodySegment

X

9



10

Southern

Santee Cooper

Southern

17. Ron Carlsen

18. Vicky Budreau

19. Shammara Hasty

SERC

SERC

SERC

SERC

Group

ChrisHiggins

10

1, 3, 5

1, 3, 5

BonnevillePowerAdministration

WesternElectricityCoordinatingCouncil

SERC

SERC

SERC

1, 3, 5

1, 3

1, 3, 5

1, 3, 5, 9

1, 3, 5

10

5

1, 5

1, 3, 6

5

1, 3, 5, 6

2

3

1, 3, 5, 6

3

10

1, 3, 5, 6

Organization

Elizeh

Kirsch

Idowu

Halpin

Doot

Albright

2. Edison

3. David

4. Ayodele

5. Fran

6. Erika

7. Meg

WECC 1

WECC 3, 5, 6

WECC 5

WECC 1

WECC 1

WECC 1

WECC 1, 3, 5, 6

Consideration of Comments: Project 2010-14.1 BAL-001-1

Murphy

Additional Member Additional Organization Region Segment Selection

1. James

8.

Group
SteveRueckert
Noadditionalmemberslisted.

7.



SERC

16. Steve Corbin

SERC

SERC

SERC

Dynegy

15. Jake Miller

24. John Troha

PowerSouth

14. Bill Thigpen

SERC

Southern

Entergy

13. Jim Case

SERC

SERC

Southern

Dynegy

12. Dan Roethemeyer

23. Antonio Grayson

Dominion VP

11. Randi Heise

SERC

22. J. T. Wood

PJM

10. Brad Gordon

SERC

SERC

SERC

LGE-KU

9. John Jackson

Southern

TVA

8. Kelly Casteel

SERC

SERC

21. Terry Coggins

LGE-KU

7. Wayne Van Liere

SERC

SERC

6. Devan Hoke

SERC

20. Melinda Montgomery Entergy

TVA

Commenter

5. Larry Akens

Group/Individual

X



1





2

X



3





4

X



5

X



6

8





7





8

RegisteredBallotBodySegment





9



X

10

Westar Energy

Westar Energy

Empire District Electric

Oklahoma Gas & Electric

Grand River Dam Authority SPP

Westar Energy

Westar Energy

5. Tiffany Lake

6. Julie Lux

7. Fred Meyer

8. Terri Pyle

9. Randy Root

10. Katie Shea

11. Bryan Taggart

1, 3, 5, 6

1, 3, 5, 6

1, 3, 5

1, 3, 5

1

1, 3, 5, 6

MISOStandardsCollaborators

SPP

SPP

SPP

SPP

SPP

1, 3, 5, 6

1, 3, 5, 6

1, 3, 5

1, 3, 5

1, 3, 5

Individual

Individual

Individual

Individual

15.

16.

17.

18.

LG&EandKUServices

3, 4, 5

DanielO'Hearn

JoeTarantino

MichaelFalvo

RobertBlohm

AntonioGrayson

PowerexCorp.

SacramentoMunicipalUtilityDistrict

IndependentElectricitySystemOperator

KeenResourcesAsiaLtd.

SouthernCompany

JimEckelkamp
ProgressEnergy
JanetSmith,Regulatory
AffairsSupervisor
ArizonaPublicServiceCompany

Brentingebrigtson

RFC

19.

AnthonyJablonski

ReliabilityFirst

Consideration of Comments: Project 2010-14.1 BAL-001-1

Individual

Additional Member Additional Organization Region Segment Selection
Mike Goodenough
Powerex Corp.
Seg 6

Individual

14.

Individual

Individual

12.

13.

Individual

1. Barbara Kedrowski We-Energies

Additional Member Additional Organization Region Segment Selection

MarieKnox

SPP

Westar Energy

4. Bo Jones

Group

SPP

3. Stephanie Huffman Cleco Power
SPP

SPP

Cleco Power

SPP

Cleco Power

2. Bryan Harper

11.



Organization

SPPStandardsReviewGroup

WECC 5

1. Louis Guidry

10.



RobertRhodes

Van Calcar

Commenter

Additional Member Additional Organization Region Segment Selection

Group

8. Pamela

9.



Group/Individual





X




X

X

X

X





1








X









X

X

2





X




X

X

X

X





3





X
















4





X




X

X

X

X





5



X

X




X

X

X

X





6

9






















7







X














8

RegisteredBallotBodySegment






















9

X




















10

Individual

Individual

Individual

Individual

Individual

Individual

Individual

Individual

Individual

Individual

22.

23.

24.

25.

26.

27.

28.

29.

30.

31.

Individual

Individual

Individual

34.

35.

36.

FrancisMonette
JohnM.Troha


KasiaMihalchuk

LauraLee

BrettHolland

AliceIreland

NicholasL.Hall

DonJones

RoLyndaShumpert

KarenWebb

DonSchmit

JayCampbell

KathleenGoodman

JohnTolo

ChrisMattson

ThadNess

MichaelGoggin

GregTravis

JeffHarrison

Commenter

HydroͲQuébecTransÉnergie
SERCReliabilityCorporation


ManitobaHydro

DukeEnergy

KCP&L

XcelEnergy

TexasReliabilityEntity
ConstellationEnergyControlandDispatch,
LLC

SouthCarolinaElectricandGas

CityofTallahassee

NPPD

NVEnergy

ISONewEnglandInc

TucsonElectricPower

TacomaPower

AmericanElectricPower

AmericanWindEnergyAssociation

IdahoPowerCompany

AECI

Organization

Consideration of Comments: Project 2010-14.1 BAL-001-1

Individual
38. Individual

37.

Individual

33.

Individual

Individual

21.

32.

Individual

20.

Group/Individual
2


























X

















X

X

X





X



X

X



X

X

X



X

X

1







X

X

X

X



X



X

X





X

X



X

X

3























X





X









4







X

X

X





X

X

X

X





X

X





X

5







X

X

X





X











X

X





X

6

10







































7

































X





8

RegisteredBallotBodySegment







































9















X























10



TheBARCSDThasdevelopedtwonewtermstobeusedwiththisstandard.

BalancingAuthorityACELimit(BAAL):ThelimitbeyondwhichaBalancingAuthoritycontributesmorethanitsshareof
Interconnectionfrequencycontrolreliabilityrisk.Thisdefinitionappliestoahighlimit(BAALHigh)andalowlimit(BAALLow).

ReportingACE:ThescanratevaluesofaBalancingAuthority’sAreaControlError(ACE)measuredinMWasdefinedinBALͲ
001whichincludesthedifferencebetweentheBalancingAuthority’sactualinterchangeanditsscheduledinterchangeplus
itsfrequencybiasobligationplusanyknownmetererror.

Doyouagreewiththeproposeddefinitionsinthisstandard?Ifnot,pleaseexplaininthecommentareabelow.



YesorNo

Consideration of Comments: Project 2010-14.1 BAL-001-1

Organization


Question1Comment
11

OneortwoofthecommentersthoughtthatthedraftingteamwassuggestingtoremovethedefinitionofACEfromtheNERC
GlossaryofTerms.ThedraftingteamexplainedthattheywerenotsuggestingtoretirethedefinitionforACE.They
wereonlytryingtocreateanewdefinitionforReportingACE.

AcoupleofcommentersfeltthattheequationforReportingAceshouldberemovedfromtheattachmentandaddedtothe
definition.Thedraftingteamagreedandmodifiedthedocumentstoreflectthesuggestion.

AfewcommentersdisagreedwiththedefinitionforNetMeterError.Thedraftingteamexplainedthatthedraftingteamagrees
withyourcommentconcerningNetMeteringError(NME)andtheyhavechangetheequationtouseInterchange
MeterError(IME).Basedoncommentsreceivedfromtheindustrythedraftingteamhaselectedtonotmakeany
modificationstohowthetermisdefined.

SeveralofthecommentersdidnotagreethatthereneededtobeanewdefinitioncreatedandaddedtotheNERCGlossaryof
TermsforBAAL.ThedraftingteamagreedandremovedthedefinitionforBAAL.

SummaryConsideration:ManyofthecommentersdisagreedwiththedefinitionofReportingAce.Thedraftingteamstatedthat
they realizedthatthisdefinitionwasmoreprescriptive.SinceACEcanvarybetweenBAsaccordingtocontrol
algorithmsthedraftingteamfeltitwasnecessarytodefinereportingACEtoensureuniformity.



1.

No

YesorNo

Italsocreatedanewterm,NetMeteringErrorthatismoreprescriptivethan
howmeteringerroriscorrectedfortoday.

ThedefinitionofreportingACEisnearlyidenticaltothecurrentdefinitionof
ACE,buttheappendixaddscomplexity.Thereshouldbenoneedforthis
newdefinition.Thedescriptionofthedefinitionintheattachmentisoverly
prescriptive.Ithasaredundantandmorerestrictiverequirementfor
frequencyresolutionthanBALͲ005.

Question1Comment

No

12

WequestiontheneedfortheReportingACEdefinition.Thereisno
explanationanywhereinthedocumentationforitsneed.Whyisthe
definitionofACEnotsatisfactory?Thedefinitionisnotevenconsistentwith
thedefinitionofACE.ThedefinitionofACEusesnetactualinterchangeand
netscheduleinterchange.WhilewearesurethattheReportingACE
definitionintendsforthesevaluestobenetvalues,questionswillarisewhy
theword“net”isincludedinonedefinitionandnottheotherina
compliancedrivenworld.Ifthedefinitionremains,wesuggeststriking
everythingafterAreaControlError.Everythingafterthisisalreadyincluded
inthedefinitionofACEtowhichthisdefinitionrefers.Theonlydifference
betweenthetwodefinitionsappearstobethatoneis“instantaneous”and
theotherisa“scanrate”.Wethink“scanrate”isnearlyinstantaneousand
satisfiesthedefinitionparticularlysinceitistheonlywaytomeasureACE
andconsideringthereareotherrequirements(BALͲ005Ͳ0.1bR8)thatspecify

Consideration of Comments: Project 2010-14.1 BAL-001-1

ACESPowerMarketingStandards
Collaborators

ThedraftingteamagreeswithyourcommentconcerningNetMeteringError(NME)andtheyhavechangetheequationtouse
InterchangeMeterError(IME).Basedoncommentsreceivedfromtheindustrythedraftingteamhaselectedtonotmakeany
modificationstohowthetermisdefined.

Response:Thankyouforyourcomment.Thedraftingteamrealizesthatthisdefinitionismoreprescriptive.SinceACEcanvary
betweenBAsaccordingtocontrolalgorithmsthedraftingteamfeltitwasnecessarytodefinereportingACEtoensure
uniformity.

ISO'sStandardsReviewCommittee

Organization

YesorNo

Furthermore,werecommendthattheACEdefinitionshouldbemodifiedto
includetheACEcalculationfromthestandard.Theequationreallyshould
bethedefinitionasitismuchmoredescriptivethanthewordsprovidedin
thedefinition.

ACEonlyhastobecalculated(whichrequiresscanningoftieͲline
measurements)onceeverysixseconds.Thebottomlineisthatthe
definitiondoesnotofferadditionalclarity.

Question1Comment

No

ThedefinitionofreportingACEisnearlyidenticaltothecurrentdefinitionof
ACE,buttheappendixaddscomplexity.Thereshouldbenoneedforthis
newdefinition.Thedescriptionofthedefinitionintheattachmentisoverly
prescriptive.Ithasaredundantandmorerestrictiverequirementfor
frequencyresolutionthanBALͲ005.Italsocreatedanewterm,Net
MeteringErrorthatismoreprescriptivethanhowmeteringerroris
correctedfortoday.

Consideration of Comments: Project 2010-14.1 BAL-001-1

13

ThedraftingteamagreeswithyourcommentconcerningNetMeteringError(NME)andtheyhavechangetheequationtouse
InterchangeMeterError(IME).Basedoncommentsreceivedfromtheindustrythedraftingteamhaselectedtonotmakeany
modificationstohowthetermisdefined.

Response:Thankyouforyourcomment.Thedraftingteamrealizesthatthisdefinitionismoreprescriptive.SinceACEcanvary
betweenBAsaccordingtocontrolalgorithmsthedraftingteamfeltitwasnecessarytodefinereportingACEtoensure
uniformity.

MRONSRF

Thedraftingteamagreeswithyourcommentconcerningaddingthecalculationandhasmodifiedthedefinition.

Response:Thankyouforyourcomment.Thedraftingteamagreeswithyourcommentconcerningaddingthetermnettothe
definitionandhasaddedtheterm.Thedraftingteamrealizesthatthisdefinitionismoreprescriptive.SinceACEcanvary
betweenBAsaccordingtocontrolalgorithmsthedraftingteamfeltitwasnecessarytodefinereportingACEtoensure
uniformity.

Organization

No

YesorNo

Question1Comment

14

4.WECCrecommendsthatalloftheseissuescanberesolveifthenewterm
ReportingACEiseliminatedandthecurrentACEtermisretained.

3.TheWECCBoardofDirectorsrecentlyapprovedaWECCRegional
VariancetoNERCBALͲ001Ͳ0.1athatwouldincludetheAutomaticTimeError
CorrectiontermintheACEdefinitionintheWesternInterconnection.WECC
isintheprocessofubmittingthisregionalvariancetoNERCforNERCBOT
consideration.Ifapproved,thereportingACEwillbedifferentforWECC.The
draftingteamaneedstobeawareofthisandtakethisintoaccount.

2.TheproposedstandardusesanewdefinitionReportingACEwhichisa
replacementofthecurrentdefinitionACEintheBALͲ001standard.While
theACEformulahasbeenrenamedasReportingACE,allreferencestoACE
inAttachment1ofBALͲ001andinotherNERCStandardshavenotbeen
changed.ThetermACEisusedinBALͲ002,BALͲ003,BALͲ004ͲWECCͲ1,BALͲ
005andIROstandards.

1.IftheexistingdefnitionofACEintheNERCGlossaryisretired,thenthe
proposeddefinitionwillbeusingtheundefinedtermACEwhichinthe
proposedstandardisnotdefined.Thedefinitioncannotrefertoan
undefinedterm.Iftheexistingdefinitionisnotretiredtheproposednew
termandtheexistingtermappeartobethesamething,andthenewterm
wouldnotbenecessary.

ReportingACE

2.BAALshouldbedefinedbytheformulausedjustlikeACEisdefinedby
componentsusedtocalculateACE

1.Itisnotclearwhatthephrase“interconnectionfrequencycontrol
reliabilityrisk“means.

BAAL

Consideration of Comments: Project 2010-14.1 BAL-001-1

WesternElectricityCoordinating
Council

Organization

YesorNo

Question1Comment

No

BPAbelievesthatthedefinitionissubjectiveandonlytheformulashouldbe
usedforthedefinition.

No

15

Further,thebenefittoreliabilityfromtheadditionofthisdefinitionis
unclear;indeed,theadditionofthisdefinitionmayactuallyresultin
confusionregardingtheappropriatemeasuresforreliableperformance.
Accordingly,theredoesnotappeartobeaneedforthisnewdefinition.
Attachment1expoundsuponthedefinitionofthetermReportingACE.This

Thecreationofanewdefinition,ReportingACE,isunnecessaryasArea
ControlErrorisalreadyadefinedterm.

Consideration of Comments: Project 2010-14.1 BAL-001-1

MISOStandardsCollaborators

Response:Thankyouforyourcomment.Thedraftingteamisnotsurewhichdefinitionyouarereferencing.IfitisBAALthe
draftingteamhasremovedthedefinitionfromthestandard.IfitisreportingACEthedraftingteambelievesthatsinceACEcan
varybetweenBAsaccordingtocontrolalgorithmsitisnecessarytodefinereportingACEtoensureuniformity.

BonnevillePowerAdministration

1Ͳ ThedraftingteamisnotsuggestingtoretirethecurrentdefinitionofACE.Itisonlyrecommendinganewdefinitionbe
added,ReportingACE.
2Ͳ TheotherstandardsthatusethetermACEwillnotbemodified.ThetermreportingACEispresentlyonlyusedinthis
standard.Thedraftingteamrealizesthatthisdefinitionismoreprescriptive.SinceACEcanvarybetweenBAsaccordingto
controlalgorithmsthedraftingteamfeltitwasnecessarytodefinereportingACEtoensureuniformity.
3Ͳ EachInterconnectionwillneedtoreviewitsstandardsasNERCreliabilitystandardsaremodified.
4Ͳ Thedraftingteamrealizesthatthisdefinitionismoreprescriptive.SinceACEcanvarybetweenBAsaccordingtocontrol
algorithmsthedraftingteamfeltitwasnecessarytodefinereportingACEtoensureuniformity.

ReportingACE

1&2–Thedraftingteamfeltthatsincethistermisonlyusedinthisstandarditisnotnecessaryforittobeincludedinthe
NERCGlossaryofTermsandhasremoveditfromthestandard.

BAAL

Response:Thankyouforyourcomment.

Organization

YesorNo

Further,thecreationofanewterm,NetMeteringError,requiresutilization
ofametercorrectionfactorthatisdifferentandmorerestrictivethanthe
netmetervaluedefinedandutilizedtoday(whichisanestimate).MISO
furthernotesthatthemetererrorutilizedinthisstandardisreferencedand
utilizedinotherBALstandardsforwhichnomodificationsarecurrently
proposed.MISOcannotsupporttheadditionoftermsandrequirements
thatmaycontradictorotherwiseconfuseRegisteredEntityobligations
underother,impactedReliabilityStandards.

descriptionisoverlyprescriptive,redundant,andmorerestrictivethanthe
performanceobligationsprovidedincomplementaryReliabilityStandards.
Forexample,theuseoffrequencyresolutionof0.0005Hzismorerestrictive
thanisrequiredunderBALͲ005.

Question1Comment

No

16

ThedefinitionforthetermBalancingAuthorityACELimit(BAAL)implies
thereisalwaysareliabilityriskforexceedingthelimit,withouttakinginto
considerationrelativeoperatingconditionsatthetime.Merelyexceeding
anACELimit(BAAL)doesnotalwaysconstitutethatthereisaninherent
reliabilityrisk,asthatwoulddependontheactualoperatingconditionsand
timingoftheoccurrenceand/ornormalfrequencycharacteristicsonthat
operatingday.Forexample:HighFrequencypriortoanextrememorning
loadpickupwithNetScheduledInterchangeout,andLowFrequencypriorto
nightlyfalloffaresometimesamorefavorablereliabilitycondition.We
recommendchangingthetexttoread“ThelimitbeyondwhichaBalancing

Consideration of Comments: Project 2010-14.1 BAL-001-1

AmericanElectricPower

ThedraftingteamagreeswithyourcommentconcerningNetMeteringError(NME)andtheyhavechangetheequationtouse
InterchangeMeterError(IME).Basedoncommentsreceivedfromtheindustrythedraftingteamhaselectedtonotmakeany
modificationstohowthetermisdefined.

Response:Thankyouforyourcomment.Thedraftingteamrealizesthatthisdefinitionismoreprescriptive.SinceACEcanvary
betweenBAsaccordingtocontrolalgorithmsthedraftingteamfeltitwasnecessarytodefinereportingACEtoensure
uniformity.

Organization

YesorNo

WeagreewiththedefinitionofthetermReportingACE,however,itshould
benotedthatBalancingAuthoritieswithmembershiptosomeRegional
PowerPoolsuseanaddedfactorofACEdiversitycomponentintheir
ReportingACEbeyondwhatismentioned.

AuthoritycontributesmorethanitsshareofInterconnectionfrequency
control’sallottedreliabilitydeviationforrequiredmeasure”.

Question1Comment

No

Thereshouldbeanequationorformulaincludedwiththedefinition

No

No

TheReportingACEdefinitionistoowordy,ambiguousandconfusing.Tosay
"Scanratevaluesof...ACE"seemsredundant.Tosay"measuredinMW
definedinBALͲ001"ͲͲͲdoesonereallyneedtodefineMW?Additionally,I
don'tseethedefinition.TheACEdefinitionseemsatoddswiththeequation
onpage#7.Isuggest:"BalancingAuthority’sAreaControlError(ACE)isthe
differencebetweentheBalancingAuthority’sactualinterchangeandits
scheduledinterchangeplusitsfrequencybiasmultipliedbythedifference
betweenactualandscheduledfrquencyplusanyknownmetererror".

IagreewiththeBAALdefinition.

Pleaseseeadditionalcommentsprovided.

Consideration of Comments: Project 2010-14.1 BAL-001-1

17

Response:Thankyouforyourcomment.ThedraftingteamfeltthatsincethetermBAALisonlyusedinthisstandarditisnot

NVEnergy

Response:Thankyouforyourcomment.

ISONewEnglandInc

Response:Thankyouforyourcomment.Thedraftingteamagreesandhasaddedtheequationtothedefinition.

TucsonElectricPower

EachInterconnectionorpowerpoolwillneedtoreviewitsstandardsasNERCreliabilitystandardsaremodified.

Response:Thankyouforyourcomment.ThedraftingteamfeltthatsincethetermBAALisonlyusedinthisstandarditisnot
necessaryforittobeincludedintheNERCGlossaryofTermsandhasremoveditfromthestandard.

Organization

YesorNo

Question1Comment

No

ThedefinitionforBAALintroducesanewconceptof“Interconnection
frequencycontrolreliabilityrisk”.Thisappearstobemanagingriskwhile
thestandardprovides“cutanddry”limits.Suggest:“Thelimitbeyond
whichaBalancingAuthoritycontributesmorethanitsshareof
Interconnectionfrequencydeviation.Thisdefinitionappliestoahighlimit
(BAALHigh)andalowlimit(BAALLow)."

No

Thedraftingteamalsoshouldtakethisopportunitytoincludeinthe
definitionfurtherclarityrelatedtoconceptssuchasACEDiversity
Interchange,DynamicSchedules,PseudoͲtiesandAutomaticTimeError
Correction.

ThedefinitionofReportingACEappearstobeoverlyprescriptive.TheWECC
hasamodifiedACEthatisworkingitswaythroughtheprocesstomakeit
clearthattheACEforcompliancepurposeswouldbecometheWECC
definedACE,nottheNERCdefinedACE.Thedraftingteamneedstotakethis
differenceintoaccountandthecurrentdraftstandarddoesnotaccountfor
thatmodification.

Consideration of Comments: Project 2010-14.1 BAL-001-1

18

Thedraftingteambelievesthatthetermsyouarereferencingaredealtwithinreferenceguideseitherinplaceorunder

Response:Thankyouforyourcomment.Thevarianceyouaredescribingisincludedinthisdraftofthestandard.

XcelEnergy

Response:Thankyouforyourcomment.ThedraftingteamfeltthatsincethetermBAALisonlyusedinthisstandarditisnot
necessaryforittobeincludedintheNERCGlossaryofTermsandhasremoveditfromthestandard.

CityofTallahassee

ThedraftingteamisnotsuggestingtoretirethecurrentdefinitionofACE.Itisonlyrecommendinganewdefinitionbeadded,
ReportingACE.

Thedraftingteamrealizesthatthisdefinitionismoreprescriptive.SinceACEcanvarybetweenBAsaccordingtocontrol
algorithmsthedraftingteamfeltitwasnecessarytodefinereportingACEtoensureuniformity.

necessaryforittobeincludedintheNERCGlossaryofTermsandhasremoveditfromthestandard.

Organization

YesorNo

No

DukeEnergydoesnotsupporttheuseofthenewterm“ReportingACE”as
weareunawareofanyissuestodatecreatedbythecurrentdefinedtermin
thestandard.Itisunderstoodthatthe“instantaneous”valueofACEisthe
currentscan,asthatistheACEmadeavailabletotheoperatorinrealͲtime.
TheReportingACEdefinitionaddsunnecessaryconfusionandshould
thereforenotbedeveloped.ACEshouldbesubstitutedinanyinstance
where“ReportingACE”isusedinthesestandards.Ifthedraftingteam
movesforwardwithitsproposaltouse“ReportingACE”,DukeEnergy
believesthattheStandardsandsupportingdocumentationneedtoclarify
thatanyreferenceto“clockͲminuteACE”meanstheclockͲminuteaverage
oftheReportingACE.

DukeEnergyagreeswiththeBalancingAuthorityACELimitdefinition.

Question1Comment

No

Inattachment1,theFA(ActualFrequency)termisdefinedandindicatesa
resolutionof±0.0005Hz.ThisshouldbechangedtoalignwiththeBALͲ005Ͳ
0.1bR17thatindicatesafrequencyresolutionч0.001Hz.

Additionally,theacronym“ACE”isdefinedintheReportingACEdefinitionbut
notintheBAALdefinition.Itshouldbedefinedateachusageoratnone.

Consideration of Comments: Project 2010-14.1 BAL-001-1

19

Response:Thankyouforyourcomment.ThedraftingteambelievesthatBALͲ001speakstothesamplerateandnotthe
accuracyofthetransducersasdetailedinBALͲ005.However,thedraftingteamhasremovedtheresolutionyouhave

ManitobaHydro



ThedraftingteamrealizesthatthisdefinitionofreportingACEismoreprescriptive.SinceACEcanvarybetweenBAsaccording
tocontrolalgorithmsthedraftingteamfeltitwasnecessarytodefinereportingACEtoensureuniformity.

Response:ThankyouforyourcommentThedraftingteamfeltthatsincethetermBAALisonlyusedinthisstandarditisnot
necessaryforittobeincludedintheNERCGlossaryofTermsandhasremoveditfromthestandard

DukeEnergy

developmentandareoutsidethescopeofthisproject.

Organization

YesorNo

Question1Comment

Yes

ReportingACEdefinition:Replace:“thedifferencebetweentheBalancing
Authority’sactualinterchangeanditsscheduledinterchangeplusits
frequencybiasobligationplusanyunknownmetererror”With:“controlͲ
errorconsiderationof:interchange,frequency,andinterchangeͲmetering
errors.”Rationale:Thissimplifieddescriptionmayexplainmorewithout
restatingtheequation.

Yes

LG&EandKUServicessuggestremoving“reliabilityrisk”fromtheendofthe
firstsentenceintheBAALdefinition

Yes

AlthoughWECCispursuingaRegionalVariationtoincludetheWECCATEC
termintothereportingACEwhichisneeded.

Yes

20

Additionally,itmaybebettertoendthedefinitionafterthephrase“as
definedinBALͲ001,”asusingarithmeticterms(differenceandplus)maynot

Thereisanexistingdefinitionfor“ControlPerformanceStandard”which
mayneedtobemodifiedordeleted.

Consideration of Comments: Project 2010-14.1 BAL-001-1

TexasReliabilityEntity

Response:Thankyouforyourcomment.Thevarianceyouaredescribingisincludedinthisdraftofthestandard.

IdahoPowerCompany

Response:Thankyouforyourcomment.ThedraftingteamfeltthatsincethetermBAALisonlyusedinthisstandarditisnot
necessaryforittobeincludedintheNERCGlossaryofTermsandhasremoveditfromthestandard.

LG&EandKUServices

Response:Thankyouforyourcomment.ThedraftingbelievesthatsinceACEcanvarybetweenBAsaccordingtocontrol
algorithmsthedraftingteamfeltitwasnecessarytodefinereportingACEtoensureuniformity.Thedraftingteamhasadded
thecalculationtothedefinition.

AssociatedElectricCooperativeInc,
JRO00088

ThedraftingteamfeltthatsincethetermBAALisonlyusedinthisstandarditisnotnecessaryforittobeincludedintheNERC
GlossaryofTermsandhasremoveditfromthestandard.

referencedfromthedraftstandard.

Organization

YesorNo
appeartomatchthecalculationinAttachment1.

Question1Comment

Yes
Yes
Yes
Yes
Yes
Yes
Yes

Yes
Yes
Yes
Yes

SPPStandardsReviewGroup

ProgressEnergy

ArizonaPublicServiceCompany

HydroͲQuébecTransÉnergie

SouthernCompany

KeenResourcesAsiaLtd.

IndependentElectricitySystem
Operator

SacramentoMunicipalUtilityDistrict

PowerexCorp.

SERCReliabilityCorporation

AECI

























Consideration of Comments: Project 2010-14.1 BAL-001-1

Yes

SERCOCStandardsReviewGroup

Thedraftingteamhasremovedthereferencetothestandardfromthedefinitionandaddedthecalculation.

21

Response:Thankyouforyourcomment.ThedraftingteambelievesthatthecurrentdefinitionforControlPerformance
Standardisstillacceptableandnomodificationisnecessary.

Organization

Yes
Yes
Yes

TacomaPower

SouthCarolinaElectricandGas

ConstellationEnergyControland
Dispatch,LLC









Consideration of Comments: Project 2010-14.1 BAL-001-1




Yes

YesorNo

AmericanWindEnergyAssociation

Organization

Question1Comment

22



TheSDThasmodifiedthedefinitionforthetermInterconnection.Pleaseviewthenewdefinitionshowninredlineonthe
UnofficialWordversionpostedontheprojectpagewhichshowsthechangesproposed.
http://www.nerc.com/filez/standards/Project2010Ͳ14.1_Phase_1_of_Balancing_Authority_RBC.html

Interconnection:Whencapitalized,anyoneofthefourmajorelectricsystemnetworksinNorthAmerica:Eastern,Western,
TexasandQuebec.

DoyouagreewiththisnewdefinitionforInterconnection?Ifnot,pleaseexplaininthecommentareabelow.



No

YesorNo

WhileweagreethatthesefourentitiescomprisethefourmajorInterconnections,
thetermisusedscoresoftimesinotherstandards.Itisbeyondthescopeofthis
draftingteamtoredefineexpectationsofotherstandards.

Question2Comment

No

23

TexasshouldbereplacedwithERCOT.AsmallportionofthestateofTexasresidesin
theWesternInterconnection.TheuseofthewordTexasmaybeconfusingbecause
ofthis.

Consideration of Comments: Project 2010-14.1 BAL-001-1

WesternElectricity
CoordinatingCouncil

Response:Thankyouforyourcomment.ThedraftingteamdisagreeswithyouregardingtheSAR.TheSARstatesthatthe
draftingteamistoaddressthedirectivesfromFERCOrder693.Oneofthesedirectiveswastoestablishacontinentwide
contingencyreservepolicy.SinceQuebecispartofthecontinentthereforethetermInterconnectionshouldbecorrected.

ISO'sStandardsReview
Committee

Organization



Manyofthecommenterswantedtheterm“Texas”changedto“ERCOT”.Thedraftingteamagreedandmadethenecessary
modificationstothedefinition.

SummaryConsideration:SeveralofthecommentersfeltthatmodifyingthedefinitionforInterconnectionwasoutsidethescopeof
thedraftingteam’sSAR.ThedraftingteamdisagreeswithyouregardingtheSAR.TheSARstatesthatthedrafting
teamistoaddressthedirectivesfromFERCOrder693.Oneofthesedirectiveswastoestablishacontinentwide
contingencyreservepolicy.SinceQuebecispartofthecontinentthereforethetermInterconnectionshouldbe
corrected.

2.

YesorNo

Question2Comment

No

No

WhileMISOagreesthatthesefourentitiescomprisethefourmajorInterconnections,
thetermisusedscoresoftimesinotherstandards.Itisbeyondthescopeofthis
draftingteamtoredefineexpectationsofotherstandards.

BPAunderstandsthatthisisanupdatetotheexistingdefinition,butitisnota
definition.Thisissimplyidentifyingtheinterconnections.

No

Pleaseuse“ERCOT”(not“Texas”)asthenameoftheInterconnection,becauseit
doesnotcovertheentirestateofTexas.Notethat“ERCOTInterconnection”isused
inAttachment1.

No

NotallofTexasisintheERCOTorTexasInterconnection,thereforetheproposed
changeislikelytocauseconfusion.AsanentitythathasaBalancingAuthorityArea
operatinginpartofthestateofTexas,wecanattesttothefactthatthereisalready
enoughconfusionintheindustryrelatedtothedifferencebetweenelectricservicein
thestateofTexasandtheInterconnectionthatoperateswhollywithinthe
boundariesofTexas.

MRONSRF

24

WhiletheNSRFagreeswiththesefourentitiescomprisethefourmajor

Consideration of Comments: Project 2010-14.1 BAL-001-1

Yes

ResponseThankyouforyourcomment.Thedraftingteamagreesandhasmadethenecessarymodification.

XcelEnergy

Response:Thankyouforyourcomment.Thedraftingteamagreesandhasmadethenecessarymodification.

TexasReliabilityEntity

Response:Thankyouforyourcomment.ThedraftingteamdisagreeswithyouregardingtheSAR.TheSARstatesthatthe
draftingteamistoaddressthedirectivesfromFERCOrder693.Oneofthesedirectiveswastoestablishacontinentwide
contingencyreservepolicy.SinceQuebecispartofthecontinentthereforethetermInterconnectionshouldbecorrected.

MISOStandardsCollaborators

Response:Thankyouforyourcomment.

BonnevillePower
Administration

Response:Thankyouforyourcomment.Thedraftingteamagreesandhasmadethenecessarymodification.

Organization

YesorNo
Interconnections,thetermisusedscoresoftimesinotherstandards.Itisbeyond
thescopeofthisdraftingteamtoredefineexpectationsofotherstandards.

Question2Comment

Yes

WhileweagreewiththesefourentitiescomprisethefourmajorInterconnections,
thetermisusedscoresoftimesinotherstandards.Itisbeyondthescopeofthis
draftingteamtoredefineexpectationsofotherstandards.

Yes

Yes

Yes
Yes

HydroͲQuébecTransÉnergie

AssociatedElectric
CooperativeInc,JRO00088







Consideration of Comments: Project 2010-14.1 BAL-001-1

Yes

ManitobaHydro

25

Thoughthisdefinitionappearsappropriate,ifthe“Texas”Interconnectionincludes
operationofareasoutsideofthestateofTexas,anothernameshouldbeconsidered.

Somewhatvaguedefinition.It'smoreidentifyingtheinterconnections.

Response:Thankyouforyourcomment.Thedraftingteamagreesandhasmadethenecessarymodification.

DukeEnergy

Response:Thankyouforyourcomment.

TucsonElectricPower

Response:Thankyouforyourcomment.ThedraftingteamdisagreeswithyouregardingtheSAR.TheSARstatesthatthe
draftingteamistoaddressthedirectivesfromFERCOrder693.Oneofthesedirectiveswastoestablishacontinentwide
contingencyreservepolicy.SinceQuebecispartofthecontinentthereforethetermInterconnectionshouldbecorrected.

IndependentElectricity
SystemOperator

Response:Thankyouforyourcomment.ThedraftingteamdisagreeswithyouregardingtheSAR.TheSARstatesthatthe
draftingteamistoaddressthedirectivesfromFERCOrder693.Oneofthesedirectiveswastoestablishacontinentwide
contingencyreservepolicy.SinceQuebecispartofthecontinentthereforethetermInterconnectionshouldbecorrected.

Organization

Yes

Yes
Yes
Yes
Yes

Yes
Yes
Yes

Yes
Yes
Yes
Yes

SERCOCStandardsReview
Group

SPPStandardsReviewGroup

ProgressEnergy

SERCReliabilityCorporation

ArizonaPublicService
Company

SouthernCompany

KeenResourcesAsiaLtd.

SacramentoMunicipalUtility
District

PowerexCorp.

AECI

IdahoPowerCompany

AmericanWindEnergy
Association



























Consideration of Comments: Project 2010-14.1 BAL-001-1

Yes

YesorNo

ACESPowerMarketing
StandardsCollaborators

Organization

Question2Comment

26



Yes
Yes
Yes
Yes
Yes

Yes

TacomaPower

ISONewEnglandInc

NVEnergy

CityofTallahassee

SouthCarolinaElectricand
Gas

ConstellationEnergyControl
andDispatch,LLC
















Consideration of Comments: Project 2010-14.1 BAL-001-1



Yes

YesorNo

AmericanElectricPower

Organization

Question2Comment

27





No

YesorNo

AECIagreeswiththepostedforballotProject_2010Ͳ14Ͳ1_BALͲ001Ͳ
1_Standard_Clean_20120604_final_rev1copy,where“insupportofinterconnection
frequency.”isdeleted.

Question3Comment

No

28

WethinkthepurposestatementshouldbemodifiedtostatethatitissteadyͲstate
frequencythatisbeingcontrolled.Otherwise,transientfrequenciesareincluded
whichisproblematicconsideringevenstableswingsinfrequencycouldeasilyexceed
thefrequencyboundsestablishedinthestandard.

Consideration of Comments: Project 2010-14.1 BAL-001-1

ACESPowerMarketing
StandardsCollaborators

Response:Thankyouforyourcomment.Thedraftingteamagreeswithyourcomment.Thiswasanerrorinthecommentreport.

AssociatedElectric
CooperativeInc,JRO00088

Organization



Acoupleofcommenterswantedtoaddthephrase“bybalancingrealpowersupplyanddemandinrealͲtime”tothepurpose
statement.Thedraftingteamstatedthattheyagreedthatcontrollinginterconnectionfrequencyisaccomplishedby
balancingpowersupplyanddemand.However,thedraftingteambelievesthataddingtheadditionalwordsdoesnot
provideanyadditionalclarity.

Afewofthecommenterswantedtoaddtheterm“steadyͲstate”tothepurposestatement.Thedraftingteamexplainedthat
frequencyisalwaysdynamic.ThedraftingteambelievesthataddingthetermsteadyͲstatewouldrequireadditional
clarityastothemeaningofsteadyͲstateandcouldcreateambiguity.

SummaryConsideration:Severalofthecommenterdisagreedwiththeuseoftheterm“insupportofinterconnectionfrequency”in
thepurposestatement.Thedraftingteamstatedthattheyagreedwiththeircomment.Thisfurtherexplainedthat
thiswasanerrorinthecommentreport.

3.TheproposedPurposeStatementforthedraftstandardis:

TocontrolInterconnectionfrequencywithindefinedlimitsinsupportofinterconnectionfrequency.
Doyouagreewiththispurposestatement?Ifnot,pleaseexplaininthecommentareabelow.

YesorNo

Question3Comment

No

Delete“insupportofinterconnectionfrequency”.

No

Thepurposestatementreferencedabovedoesnotmatchthestandard.The
standardstates:“TocontrolInterconnectionfrequencywithindefinedlimits”.It
doesnotinclude“insupportofinterconnectionfrequency”.Pleaseclarifywhichone
iscorrect.

No

WhileMISOagreeswiththePurposeprovidedinthestandards,itnotesthatthe
phrasedefinedaboveisnotconsistentwiththePurposeprovidedintheversionof
BALͲ001Ͳ1postedforcomment.

No

ThepostedBALͲ001Ͳ1showsthePurposeStatementas:Purpose:Tocontrol
Interconnectionfrequencywithindefinedlimits.Thepurposestatementinthedraft
standardispreferredoverthePurposeStatementasshowninQuestion3.

No

29

ConclusiveresultsoftheBAALfieldtrialarenotprovidedinthebackground

ItisnotclearthatthisStandardaidsinthecontroloffrequencywithindefinedlimits,
particularlyfortransientfrequencydeviationstoavoidUFLSoperation.

Consideration of Comments: Project 2010-14.1 BAL-001-1

ProgressEnergy

Response:Thankyouforyourcomment.Thedraftingteamagreeswithyourcomment.Thiswasanerrorinthecommentreport.

LG&EandKUServices

Response:Thankyouforyourcomment.Thedraftingteamagreeswithyourcomment.Thiswasanerrorinthecommentreport.

MISOStandardsCollaborators

Response:Thankyouforyourcomment.Thedraftingteamagreeswithyourcomment.Thiswasanerrorinthecommentreport.

BonnevillePower
Administration

Response:Thankyouforyourcomment.Thedraftingteamagreeswithyourcomment.Thiswasanerrorinthecommentreport.

SERCReliabilityCorporation;
SERCOCStandardsReview
Group

Response:Thankyouforyourcomment.Thedraftingteambelievesthatfrequencyisalwaysdynamic.Thedraftingteambelieves
thataddingthetermsteadyͲstatewouldrequireadditionalclarityastothemeaningofsteadyͲstateandcouldcrateambiguity.

Organization

YesorNo

document.Iftheindustryistomakethemovetomakethischange,thereshouldbe
evidenceprovidedthatthisactionwillaidinbetterfrequencycontrolforthe
Interconnections.

Question3Comment

No

PowerexbelievesthatthedevelopmentoftheBALͲ001standardbasedonthe
currentpurposestatementwillallowentitiestocreatedeliberateinadvertentflows
withinthestandardsboundaries,withoutregardtotheimpacttotransmission
customersonthegrid.Thismayresultinsubstantialcurtailmentstotransmission
customersindirectcontraventionoftheCommission’sopenaccesstransmission
principles.

No,thePurposeStatementisinadequate.Thepurposeofthestandardshouldbeto
controlBAAACEwithindefinedlimitsinsupportofInterconnectionFrequency,and
topreventBAAACEfromhavingadetrimentalimpacttootherentitiesonthegrid.In
OrderNo.890,theFederalEnergyRegulatoryCommission(FERCortheCommission)
recognizedthepotentialforinadvertentenergyflowsbetweenadjacentBAstoboth
jeopardizereliabilityandtocauseundueharmtocustomersonthegrid.Such
inadvertentenergyflowsaredrivenbythesizeofeachBAAsACE,asprimarily
containedbyCPS2underthecurrentBALͲ001,andthenewproposedBALͲ001
standard.

Consideration of Comments: Project 2010-14.1 BAL-001-1

30

BAALwasdesignedtoprovideforbettercontrolbyallowingpowerflowsthatdonothaveadetrimentaleffectonreliabilitybut

Response:Thankyouforyourcomment.Thedraftingteamunderstandsyourconcern.However,thedraftingteamdoesnot
knowofanyanalysisthathasbeendonethatdirectlytiestheuseofBAALwiththeproblemsthatyouhaveidentified.

PowerexCorp.

ThedraftingteamconductsamonthlycalltodiscussthepriormonthoperationusingBAAL.Thesemonthlyresultsarepostedon
theNERCwebsite.TheBAALfieldtrialwillcontinueineffectuntilthedatethatanewstandardgoesintoeffect.Thedrafting
teamwillbepreparingareportbasedonthefieldtrialresultsthatwillbepostedpriortotheFERCfilingforthisdraftstandard.

Response:Thankyouforyourcomment.ThedraftingteambelievesthattransientfrequencydeviationstoavoidUFLSare
addressedintheproposedBALͲ003Ͳ1standard.

Organization

YesorNo

No

Delete“insupportofinterconnectionfrequency”.

Question3Comment

No

Thispurposestatementdoesnotmatchthepurposestatementintheproposed
Standard.

No

Mysuggestion:"TocontrolInterconnectionfrequencywithindefinedlimits."

No

TheCityofTallahassee(TAL)isunsureoftheclarityofthispurpose
statement.Suggest:TocontrolindividualBalancingAreaACEdeviationwithindefined
limitsinsupportofinterconnectionfrequency.

No

SouthCarolinaElectricandGassupportsthecommentssubmittedbytheSERCOC
StandardsReviewGroup

No

31

Wesuggestamoreprecisepurposestatementasfollows:“Tocontrol
Interconnectionfrequencywithindefinedlimitsbybalancingrealpowersupplyand
demandinrealͲtime.”

Consideration of Comments: Project 2010-14.1 BAL-001-1

TexasReliabilityEntity

Response:Thankyouforyourcomment.Thedraftingteambelievesthatfrequencyisalwaysdynamic.Thedraftingteambelieves
thataddingthetermsteadyͲstatewouldrequireadditionalclarityastothemeaningofsteadyͲstateandcouldcrateambiguity.

SouthCarolinaElectricand
Gas

Response:Thankyouforyourcomment.Thedraftingteamdisagreeswithyoursuggestion.Thedraftingteambelievesthatthis
standardshouldaddressInterconnectionfrequencywhichisachievedbyindividualBAcontrolperformance.

CityofTallahassee

Response:Thankyouforyourcomment.Thedraftingteamagreeswithyourcomment.Thiswasanerrorinthecommentreport.

NVEnergy

Response:Thankyouforyourcomment.Thedraftingteamagreeswithyourcomment.Thiswasanerrorinthecommentreport.

TucsonElectricPower

Response:Thankyouforyourcomment.Thedraftingteamagreeswithyourcomment.Thiswasanerrorinthecommentreport.

AECI

restrictthosethatdohaveadetrimentaleffectonreliability.

Organization

YesorNo

Question3Comment

No

Thepurposedoesnotmakesense.Inordertomakeitclearer,endthesentenceafter
theword“limits.”Withthischange,itwouldalsobeacceptabletoaddthephrase
“duringnormaloperations”aftertheword“limits”.

No

Additionally,theBackgrounddocumentusestheterm“predefinedlimits”whichisa
moreaccuratedescription.

ThePurposeStatementinthedraftdiffersfromwhatispresentedinquestion3and
states“TocontrolInterconnectionfrequencywithindefinedlimits”.Thepurpose
statedinthisquestionispreferable,withcapitalizationoftheseconduseof
interconnection.Add“insupportofInterconnectionfrequency”totheproposed
PurposeStatement.

Yes

Delete"insupportofinterconnectionfrequency".It'sredundant,andchildishly
repetitiveofthesameterm.Youdon'tcontrolsomethingtowithinlimitsinorderto
undermine(=notsupport)thoselimits!

Yes

32

Asmentionedinlatercomments,thespecificpurposeofR2seemstobethe
developmentofaboundaryforACEdeviation,withconsiderationgiventofrequency
support.EspeciallygiventhemannerinwhichR2attemptstocontrolforfrequency,

Consideration of Comments: Project 2010-14.1 BAL-001-1

ConstellationEnergyControl
andDispatch,LLC

Response:Thankyouforyourcomment.Thedraftingteamagreeswithyourcomment.Thiswasanerrorinthecommentreport.

KeenResourcesAsiaLtd.

Response:Thankyouforyourcomment.Thiswasanerrorinthecommentreport.However,basedoncommentsreceivedfrom
theindustrythedraftingteamhasdecidedtonotmakethemodificationyousuggest.

DukeEnergy

Response:Thankyouforyourcomment.Thedraftingteamagreeswithyourcomment.Thiswasanerrorinthecommentreport.

XcelEnergy

Response:Thankyouforyourcomment.Thedraftingteamagreesthatcontrollinginterconnectionfrequencyisaccomplishedby
balancingpowersupplyanddemand.However,thedraftingteambelievesthataddingtheadditionalwordsdoesnotprovideany
additionalclarity.

Organization

YesorNo

Yes
Yes
Yes
Yes
Yes

Yes
Yes

Yes

Yes
Yes

ManitobaHydro

MRONSRF

HydroͲQuébecTransÉnergie

SPPStandardsReviewGroup

ArizonaPublicService
Company

SouthernCompany

IndependentElectricity
SystemOperator

SacramentoMunicipalUtility
District

IdahoPowerCompany

AmericanWindEnergy
Association

Question3Comment























itsintentisclearlynotthesimplesupportorcontroloffrequency.

Consideration of Comments: Project 2010-14.1 BAL-001-1

Yes

ISO'sStandardsReview
Committee

Response:Thankyouforyourcomment.

Organization

33

Yes
Yes

TacomaPower

ISONewEnglandInc







Consideration of Comments: Project 2010-14.1 BAL-001-1





Yes

YesorNo

AmericanElectricPower

Organization

Question3Comment

34






Consideration of Comments: Project 2010-14.1 BAL-001-1

35

Anothercommenterthoughtthatreferencinganattachmentintherequirementwouldcreaterequirementswithintheattachment.
Thedraftingteamexplainedthattheattachmentwasnotcreatinganyadditionalrequirements.Theattachmentonly
providesthecalculationmethodology.Thedraftingteambelievesthattherequirementsshouldonlystatewhatan
entityissupposedtodo,nothowtocalculatesomething.

Onecommenterquestionedwhetheranattachmentwasconsideredpartofastandardandthereforeenforceable.Theyalsowere
unsureofhowmodificationstoanattachmentwouldbehandled.Thedraftingteamstatedthattheattachmentwas
partofthestandardandisthereforeenforceable.Tomakeanymodificationstoanattachmentyoumustgothrough
thesameprocess(theStandarddevelopmentProcess)asifyouwerechangingarequirement.

OnecommenterexpressedconcernwiththeuseofReportingACEandthatsomeoftheequationswerestillusingACE.Thedrafting
teamexplainedthattheequationshadbeenchangedtouseReportingACE.Thedraftingteamfurtherstatedthat
sinceACEcanvarybetweenBAsaccordingtocontrolalgorithmsthedraftingteamfeltitwasnecessarytodefine
reportingACEtoensureuniformity.

Afewofthecommentersdisagreedwiththephrase“tosupportInterconnectionFrequency”.Thedraftingteamagreedwiththe
commenterandremovedthelanguagefromtherequirement.

SummaryConsideration:manyofthecommentersthoughtthatthepresentwordingofRequirementR1wassufficientandshould
notbechanged.Thedraftingteamstatedthatthey hadonlymademinormodificationstotheproposedrequirement
fromthepresentrequirement.ThewordingforRequirementR1isvirtuallythesameasitistoday.Thedraftingteam
doesnotknowofanyissuesthathavearisenwiththepresentwording.

4.TheBARCSDThasdevelopedRequirementR1tomeasurehowwellaBalancingAuthorityisabletocontrolitsgenerationand
loadmanagementprograms,asmeasuredbyitsAreaControlError(ACE),tosupportsitsInterconnection’sfrequencyovera
rollingoneyearperiod.

R1.EachBalancingAuthorityshalloperatesuchthattheBalancingAuthority’sControlPerformanceStandard1(CPS1),as
calculatedinAttachment1,isgreaterthanorequalto100%fortheapplicableInterconnectioninwhichitoperatesforeach12
monthperiod,evaluatedmonthly,tosupportinterconnectionfrequency.

DoyouagreewiththisRequirement?Ifnot,pleaseexplaininthecommentareabelow.

No

YesorNo

Question4Comment

Consideration of Comments: Project 2010-14.1 BAL-001-1

36

5.ItisnotclearwhythecalculationforCPS1wasmovedfromthestandardtothe
attachment.Areattachmentspartofthestandardandifsomusttheygothroughthe
standardsdevelopmentprocedureifamodificationoftheequationismade?Willthe
industrybegivenachancetocomment/ballotonanychangesmadetotheformulas
iftheyarenotpartofthestandard.Whatprocesswillbeusedtochangecontentin
theattachment1andwilltheindustryhaveopportunitiestocommentandballoton
thechanges?

4.Theattachment1definesReportingACEandessentiallyremovingthedefinition
fortheterm“ACE”buttheformulasinattachment1stillrefertoACE.WECC
recommendsreplacingtheproposedReportingACEwithACEwhichalsoaddresses
theinconsistencywithallotherNERCstandardsthatrefertothetermACE.

3.Inattachment1thetermNMEintheACEequationreplacestheexistingtermIME.
Thedefinitionitselfhasnotchangedsignificantlybutjusttheacronym.WECChas
RegionalStandardBALͲ004ͲWECCͲ1thatreferstothetermIMEandrecommends
thattheSDTretaintheexistingtermanddefinitionofIME.

2.InAttachment1thedefinitionsforNetInterchangeActualandNetInterchange
Schedulehavebeenchangedbuttheyarenotincludedinthedefinitionsectionofthe
standard.TheSDTneedstoclarifyifthesenewdefinitionswillreplacetheexisting
approveddefinitionsintheglossary

1.Thephrase“tosupportinterconnectionfrequency”doesnotaddanythingtothe
requirementandshouldbedeleted.IfaBAbarelymissedinonemonthbutwas
compliantforthe12Ͳmonthperiod,wouldthatBAfailtosupportinterconnection
frequency?

1)Thedraftingteamagreesandhasremovedthelanguage.

Response:Thankyouforyourcomment.

WesternElectricity
CoordinatingCouncil

Organization



YesorNo

Question4Comment

No

BPAfavorsthepreviousversionoftherequirement.Referringtotheattachment
createsmanyrequirementswithinoneidentifiedrequirementwithoutbreakingthem
out.BPAbelievesthereshouldbeonlyonerequirementwithineachoftheidentified
requirements.

No

37

Additionally,MISOnotesthatthelanguageutilizedinR1indicatesonlythe
requirementtoutilizea12Ͳmonthperiod,butdoesnotprescribethatthetimeperiod
bea“rollingtwelvemonth”periodasisindicatedintheVSLsectionorasthe“most

MISOagreesthatperformanceshouldbeevaluatedusinga12monthperiod
evaluatedonamonthlybasis,butrequestsclarificationthatsubstandard
performanceinonemonthwouldnotresultinmanymonthsofoffͲnormal
performance.Morespecifically,becausetheinclusionofonemonthofoffͲnormal
performanceapparentlywouldbecarriedthroughmultiplemonthlycalculations,the
impactofthatonemonthofoffͲnormalperformancewouldberetaineduntilit“rolls
out”ofthetimeframerequiredforcalculationoftheaverage.Accordingly,a
BalancingAuthority’sperformancecouldbeimpactedforasignificantlylongerperiod
oftimethanthetimeperiodforwhichperformancewasactuallyimpacted.

Consideration of Comments: Project 2010-14.1 BAL-001-1

MISOStandardsCollaborators

Response:Thankyouforyourcomment.Thedraftingteamdisagreeswithyourcomment.Theattachmentdoesnotcreateany
additionalrequirements.Theattachmentonlyprovidesthecalculationmethodology.Thedraftingteambelievesthatthe
requirementsshouldonlystatewhatanentityissupposedtodo,nothowtocalculatesomething.

BonnevillePower
Administration

5)Theattachmentispartofthestandardandisthereforeenforceable.Tomakeanymodificationstoanattachmentyoumustgo
throughthesameprocess(theStandarddevelopmentProcess)asifyouwerechangingarequirement.

4)TheequationshavebeenchangedtouseReportingACE.ThedraftingteamrealizesthatthisdefinitionofreportingACEismore
prescriptive.SinceACEcanvarybetweenBAsaccordingtocontrolalgorithmsthedraftingteamfeltitwasnecessarytodefine
reportingACEtoensureuniformity.

3)ThedraftingteamagreesandhasmadethemodificationtonowuseIME.

2)Thedraftingteamisnotattemptingtomodifytheexistingdefinitions.Thetermshavebeenchangedintheattachment.

Organization

YesorNo

recentconsecutivetwelvemonths”asisindicatedinAttachment1.MISOsuggests
thatalllanguageinthestandardregardingthetwelvemonthperiodbestandardized
toensurethatRegisteredEntityobligationsareclearandunambiguous.

Question4Comment

No

ThereappearstobenochangeinCPS1calculationsorrequirementssothecurrent
BALͲ001Ͳ0.1aispreferred.

No

38

Additionally,wecontinuetohavereliabilityconcernswiththeBAALlimitsnot
accountingforlargeACEexcursionsandthepossibilityforanincreaseintransmission
limitexceedencesassociatedwithsuchoperation.WebelievetheInterconnection
willbefurtherexposedduetothelackofACEboundingtosomehowreflect
transmissionlimits,andcontinuetobelievethatCPS2isamorereliablemetric.

WeareconcernedthatCPS1alonewillnotaddressadequatelythetimeofdayshort
termfrequencyexcursionsobservedontheEasternInterconnection.

Webelievethatthefrequencymodelanditsuseof3*Epsilonforfrequencytrigger
limitshassignificantshortcomings.Thelevelofreliabilitytargetedandachievedisa
functionofunderfrequencyrelaysettings,interconnectionfrequencyresponse,and
thesizeandexpectedoutagerateofthedesigncontingency(s)forwhichprotectionis
needed.3*Epsilonisnotsensitivetothesevaluesorchangesinthemovertime.Itis
notcoordinatedwiththemodelintheFrequencyResponseStandardunder
development,whichdoesaddressthesesensitivities.

Consideration of Comments: Project 2010-14.1 BAL-001-1

ISONewEnglandInc

Response:Thankyouforyourcomment.Thedraftingteamhasonlymademinormodificationstotheproposedrequirementfrom
thepresentrequirement.ThewordingforRequirementR1isvirtuallythesameasitistoday.

TucsonElectricPower

Response:Thankyouforyourcomment.Thedraftingteamhasonlymademinormodificationstotheproposedrequirementfrom
thepresentrequirement.ThewordingforRequirementR1isvirtuallythesameasitistoday.Thedraftingteamdoesnotknowof
anyissuesthathavearisenwiththepresentwording.Thepresentrequirementdoesnotstatearolling12Ͳmonths.Thedrafting
teamhasmodifiedtheattachmenttousethesamelanguagethroughout.

Organization

YesorNo

Question4Comment

No

Thelastphrase“tosupportinterconnectionfrequency”makestherequirement
unclear.Doesthislanguagemeanthatfrequencyisnotallowedtogetoutsideof
definedparametersmeanthattherehasbeenaviolationofthestandardbyanentity
withintheinterconnection?Pleasedeletethatphrasesotherequirementisclear
andconcise.

Yes

2)Thepurposeofaveragingistoaccountforboththegoodandbadperformances
experiencedoverthe12monthsinquestion.WesuggestthattheSDTdevelopa
criterionthatidentifiesagivenmonthperformanceasbeingoutoflimitsandthatthe
performanceissogoodorsobadthatthemonthlyvalueeitherbedroppedfromthe
averagingoritbesubstitutedwiththelimitingvalue.

1)Whileweagreethatthe12monthrollingaverageperformanceisevaluated
monthly,thatdoesnotmeanthatsubstandardperformanceinonemonthshould
resultinmanymonthsofrepeatviolationsuntilthatbadmonthrollsouttheaverage.
NonͲcomplianceshouldonlyaccrueiftheBAisnotunderamitigationplanandhas
newmonthsofnonͲcompliantperformance.

Consideration of Comments: Project 2010-14.1 BAL-001-1

39

Response:Thankyouforyourcomment.Thedraftingteamhasonlymademinormodificationstotheproposedrequirementfrom
thepresentrequirement.ThewordingforRequirementR1isvirtuallythesameasitistoday.Thedraftingteamdoesnotknowof
anyissuesthathavearisenwiththepresentwording.Thepresentrequirementdoesnotstatearolling12Ͳmonths.Thedrafting

ISO'sStandardsReview
Committee

Response:Thankyouforyourcomment.Thedraftingteamagreesandhasremovedthelanguage.

XcelEnergy

Thedraftingteamhasnotseenanyissuesthatyouaredescribingoccurduringthefieldtrialthatcanbedirectlyattributableto
theuseofBAAL.

Thedraftingteamhasnotseenanyissuesconcerningthe“timeofdayshorttermfrequencyexcursions”duringthefieldtrial.

Response:Thankyouforyourcomment.ThedraftingteamassumesyouarecommentingonBAAL.BAALwasdesignedto
provideforbettercontrolbyallowingpowerflowsthatdonothaveadetrimentaleffectonreliabilitybutrestrictthosethatdo
haveadetrimentaleffectonreliability

Organization

YesorNo

Yes

AlthoughManitobaHydroagreeswiththisRequirement,wesuggestthefollowing
clarificationstotheRequirementwording.Thewords‘ascalculatedinAttachment1’
shouldbereplacedwith‘calculatedinaccordancewithAttachment1’forclarity.The
referenceto‘it’shouldspecifytheBalancingAuthorityforclarity.

Question4Comment

Yes

Yes

Yes

WhiletheNSRFagreesthatthe12monthrollingaverageperformanceisevaluated
monthly,thatdoesnotmeanthatsubstandardperformanceinonemonthshould
resultinmanymonthsofrepeatviolationsuntilthatbadmonthrollsouttheaverage.
NonͲcomplianceshouldonlyaccrueiftheBAisnotunderamitigationplanandhas
newmonthsofnonͲcompliantperformance.

Wethankthedraftingteamformakingitperfectlyclearthatonlytherolling12
monthCPS1calculationissubjecttocomplianceandnottheonemonthcalculation.

AECIagreeswiththisexistingandunmodifiedrequirement.

Yes

40

Thisisanexistingrequirementandwasnotmodifiedbythestandarddraftingteam.

Consideration of Comments: Project 2010-14.1 BAL-001-1

SERCOCStandardsReview
Group

Response:Thankyouforyourcomment.Thedraftingteamhasonlymademinormodificationstotheproposedrequirementfrom
thepresentrequirement.ThewordingforRequirementR1isvirtuallythesameasitistoday.Thedraftingteamdoesnotknowof
anyissuesthathavearisenwiththepresentwording.Thepresentrequirementdoesnotstatearolling12Ͳmonths.Thedrafting
teamhasmodifiedtheattachmenttousethesamelanguagethroughout.

MRONSRF

Response:Thankyouforyourcomment.

ACESPowerMarketing
StandardsCollaborators

Response:Thankyouforyourcomment.

AssociatedElectric
CooperativeInc,JRO00088

Response:Thankyouforyourcomment.Thedraftingteamagreesandhasmodifiedtherequirementaccordingly.

ManitobaHydro

teamhasmodifiedtheattachmenttousethesamelanguagethroughout.

Organization

YesorNo

Yes

Yes
Yes

Yes
Yes
Yes
Yes

Yes

Yes
Yes
Yes

HydroͲQuébecTransÉnergie

ArizonaPublicService
Company

SouthernCompany

KeenResourcesAsiaLtd.

pwx

IndependentElectricity
SystemOperator

SacramentoMunicipalUtility
District

PowerexCorp.

AECI

IdahoPowerCompany

Question4Comment























41

SouthCarolinaElectricandGassupportsthecommentssubmittedbytheSERCOC
StandardsReviewGroup

Consideration of Comments: Project 2010-14.1 BAL-001-1

Yes

SPPStandardsReviewGroup

Response:Thankyouforyourcomment.

SouthCarolinaElectricand
Gas

Response:Thankyouforyourcomment.

Organization



Yes
Yes
Yes
Yes
Yes
Yes

Yes

AmericanElectricPower

TacomaPower

NVEnergy

CityofTallahassee

TexasReliabilityEntity

ConstellationEnergyControl
andDispatch,LLC

DukeEnergy


















Consideration of Comments: Project 2010-14.1 BAL-001-1



Yes

YesorNo

AmericanWindEnergy
Association

Organization

Question4Comment

42




Consideration of Comments: Project 2010-14.1 BAL-001-1

43

OnecommenterfeltthattheeliminationofCPS2couldhaveadetrimentalimpactonreliabilitywhenfrequencyisintheopposite
direction.ThedraftingteamstatedthatneitherBAALnorCPS2guaranteesthataBAwhosegenerationisinadirection

AcoupleofothercommenterswereconcernedthatasmallBAsoperationcouldbemorerestrictiveunderBAAL.Thedraftingteam
statedthattheywereawareoftheconcernidentified.However,thedraftingteamisattemptingtodevelopa
standardthatwouldbeapplicabletotheentirecontinentanddoesnotknowofanymethodtodistinguishbetween
largerandsmallerBAs.

AfewofthecommentersfeltthatBAswouldoperateinamannerthatwouldallowthemtobenonͲcompliantforalargepartofthe
30ͲminutewindowusedbyBAALandthattheyhadseenthisoperationusedbyBAsinthewest.Thedraftingteam
explainedthattooperateinthemannertheyhaddescribedwouldbeaveryhighriskmethodofoperation.The
draftingteambelievesthattheperformanceoftheBAswouldnotbecomeworsebutwouldinfactbebetterifthereif
thisstandardwasenforceableandtherewerecompliancepenaltiesinvolved.

Acoupleof thecommentersdisagreedwiththephrase“tosupportInterconnectionFrequency”.Thedraftingteamagreedwiththe
commenterandremovedthelanguagefromtherequirement.

AfewofthecommenterswantedtochangetheequationsforBAALfromusing60HztouseScheduledFrequency.Thedraftingteam
agreedandmadethenecessarymodifications.

SummaryConsideration:SeveralcommentersfeltthatusingBAAlhascausedincreasedinadvertentflowsandtransmissionissues.
Thedraftingteamstatedthattheyhadnotseenanyissuesthatyouaredescribingoccurduringthefieldtrialthatcan
bedirectlyattributabletotheuseofBAAL.BAALwasdesignedtoprovideforbettercontrolbyallowingpowerflows
thatdonothaveadetrimentaleffectonreliabilitybutrestrictthosethatdohaveadetrimentaleffectonreliability.

5. TheBARCSDThasdevelopedRequirementR2toenhancethereliabilityofeachInterconnectionbymaintainingfrequencywithin
predefinedlimitsunderallconditions.

R2.EachBalancingAuthorityshalloperatesuchthatitsclockͲminuteaverageofReportingACEdoesnotexceedformorethan30
consecutiveclockͲminutesitsclockͲminuteBalancingAuthorityACELimit(BAAL),ascalculatedinAttachment2,fortheapplicable
Interconnectioninwhichitoperatestosupportinterconnectionfrequency..

DoyouagreewiththisRequirement?Ifnot,pleaseexplaininthecommentareabelow.



No

YesorNo

3)anyconcern,abouttimeͲerrorcorrectionsbeingsolargethattheyriskUFLfirstͲ
tiermargins,shouldbeaddressedbyexercisingsmallermagnitudecorrectionsfor
longerperiodsoftime.

2)ThisdraftwasonlyappropriatewhenourindustrybelievedthattimeͲerror
correctionswouldberetired,and

1)Ascurrentlydrafted,thisstandardpenalizesBAswhoarecomplyingwithdirected
timeͲerrorcorrections,

Rationale:

AECIisfinewiththewordingunderR2,butnotstronglyrecommendsthat
Attachment2bechangedasfollows:Replace:“60Hz”or“60”With:“Fs”And
reinstate:theearlierFsdefinition

Question5Comment

No

InHQT’sfielttrial,frequencylimitsweredefinedfrom59.9Hzto60.1Hz.The
proposedmethodologyinAppendix2doesnotreflectthosevaluessincethe
3*epsilonmethodologyleadsto59.937Hzto60.063Hzfrequencylimits.

No

44

AswithBALͲ013Ͳ1,should“clockͲminutes”bereplacedwith“minutes”?

Consideration of Comments: Project 2010-14.1 BAL-001-1

NortheastPowerCoordinating
Council

Response:Thankyouforyourcomment.Thedraftingteamacknowledgesthatyourfieldtrialisconductedusingdifferentlimits.
BAALwasdesignedtoprovideforbettercontrolbyallowingpowerflowsthatdonothaveadetrimentaleffectonreliabilitybut
restrictthosethatdohaveadetrimentaleffectonreliability.

HydroͲQuébecTransÉnergie

Response:Thankyouforyourcomment.Thedraftingteamagreesandhasmadethenecessarymodifications.

AssociatedElectric
CooperativeInc,JRO00088

Organization



thatsupportsinterconnectionfrequencywillnotresultintransmissionissues.BAswithlargeACEduringperiodswhen
transmissionissuesarepresentshouldbeaddressedbytheRC.

YesorNo

Question5Comment

No

2.ItisnotclearwhythecalculationsforBAALareincludedinattachment2.Are
attachmentspartofthestandardandifsomusttheygothroughthestandards
developmentprocedureifamodificationoftheequationismade?Willtheindustry
begivenachancetocomment/ballotonanychangesmadetotheformulasifthey
arenotpartofthestandard.Whatprocesswillbeusedtochangecontentinthe
attachment1andwilltheindustryhaveopportunitiestocommentandballotonthe
changes?

1.Thephrase“tosupportinterconnectionfrequency”doesnotaddanythingtothe
requirementandshouldbedeleted.

No

Referringtotheattachmentcreatesmanyrequirementswithinoneidentified
requirementwithoutbreakingtheout.BPAbelievesthereshouldbeonlyone
requirementwithineachoftheidentifiedrequirements.

BPAdisagreeswiththestatementinthequestionwhichsays“enhancethe
reliability”.

Consideration of Comments: Project 2010-14.1 BAL-001-1

45

Thedraftingteamdisagreeswithyourcomment.Theattachmentdoesnotcreateanyadditionalrequirements.Theattachment
onlyprovidesthecalculationmethodology.Thedraftingteambelievesthattherequirementsshouldonlystatewhatanentityis
supposedtodo,nothowtocalculatesomething.

Response:Thankyouforyourcomment.Thedraftingteamunderstandsyourdisagreementwiththequestionbutcannotprovide
aresponsewithoutfurtherinformation.

BonnevillePower
Administration

2)Theattachmentispartofthestandardandisthereforeenforceable.Tomakeanymodificationstoanattachmentyoumustgo
throughthesameprocess(theStandarddevelopmentProcess)asifyouwerechangingarequirement.

1)Thedraftingteamagreesandhasremovedthelanguage.

Response:Thankyouforyourcomment.

WesternElectricity
CoordinatingCouncil

Response:Thankyouforyourcomment.Thedraftingteambelievesthat“clockͲminutes”isamoredescriptiveterm.

Organization

No

YesorNo

WeareconcernedaboutnotbeingabletomeettheBAALcriteriaduringcertain
contingencyeventsexemptedinBALͲ002Ͳ2.Forexample,intheexistingBALͲ001Ͳ
0.1a,CPS2isamonthlyaveragevaluewherebynottotallycoveringamultiple
contingencyeventcouldbeexoneratedattheendofthemonthprovidedcontrolfor
theremainderofthemonthwassufficienttobringthemonthlyvaluetoatleast90%.
WithBAAL,weonlyhavea30Ͳminutewindowofforgivenesswhichcouldcreate
problems,makingBAALatightercontrolparameter.Wewouldsuggestatleastan
exemptionforBAALcomplianceduringeventswherebymultiplecontingenciescause
thetotalgenerationlosstobegreaterthanaBA’sorRSG’sMSSC.

Question5Comment

No

TheproposedchangesinBALͲ003withregardtovariablebias(noflooronvariable
bias)opentheopportunityforgamingR2.

No

46

SincetheRBCFieldTrialbegantheWECCaveragefrequencydeviationhasbeen
increasing.TheRBCFieldTrialresultsarenotanaccuratereliabilityassessmentasnot
allparticipatingBalancingArea’sEnergyManagementSystemshaveCPS1Ͳonly
controlcapabilityand,thus,arenotfullyparticipating.CPS2isdesignedtolimita
BalancingArea’sunscheduledpowerflowsanddoesnothaveafrequency
componentͲthatiswhatCPS1isdesignedtomeasure.ThenewBAALstandardwill

YesonVRFs

AZPShasnotbeenconvincedthattheRBCisabetterformofcontrolthenwhatis
currentlyinplace.

Consideration of Comments: Project 2010-14.1 BAL-001-1

ArizonaPublicService
Company

Response:Thankyouforyourcomment.Thedraftingteamdisagreeswithyourcomment.ThelatestdevelopmentsinBALͲ003
provideminimumvaluesforFrequencyBiassettingswhenvariablebiasisusedinmultiͲBAinterconnections.

MISOStandardsCollaborators

Response:Thankyouforyourcomment.Thedraftingteambelievesthatthisstandardisdealingwithregulatingreservesandnot
deploymentofcontingencyreserves.Thedraftingteamhasnotseentheissuethatyouaredescribingoccurduringthefieldtrial
thatcanbedirectlyattributabletotheuseofBAAL.BAALwasdesignedtoprovideforbettercontrolbyallowingpowerflowsthat
donothaveadetrimentaleffectonreliabilitybutrestrictthosethatdohaveadetrimentaleffectonreliability.

SPPStandardsReviewGroup

Organization

YesorNo

CPS2allowsaBalancingAreatobenonͲcompliantfor72hours(10%)eachmonth.
UndertheproposedBAALstandard,aBalancingAreacanbenonͲcomplianttwentyͲ
nineminutesofeach30minuteperiodwhichis696hours(96%)permonth.Thiswill
betakenadvantageoftothedetrimentofreliability.

allowfarmoreunscheduledpowerflowswhentheInterconnectionfrequency
remainsnearnominal,whichitpredominatelydoes.

Question5Comment

No

47

IntheBackgroundDocumentforthestandardthedraftingteampointedoutthat
CPS2“...allowssignificanthourswhenaBalancingAuthority’sACEvaluesare
unbounded.”BecauseR2oftheproposedstandardwillallowBAstocyclically
operateoutsidetheBAALlimitasdescribedabove,theproblemofBA’soperating
withanunboundedACEcouldactuallybecomeworseundertheproposedstandard,
notbetter.

No.Thestandardisinadequate.TherequirementwillallowBA’stooperateinaway
thatcouldsignificantlyincreaserisktotheinterconnection,forupto30minutes,
withoutpenalty.Worse,itwillallowBA’sto“sawtooth”:operateoutsidetheBAAL
limitforextendedperiodsoftime(upto30minutes),changeoperationsforaslittle
asoneminutetobringtheirACEbackintotheBAALlimittoresetthe30minute
clock,andthenagainstartoperatingoutsidetheBAALlimit,anddosocyclically,for
extendedperiods.ThisbehaviorwasexhibitedtosomeextentbyseveralBAsduring
thefieldtrial,sothereshouldbeeveryexpectationthatthistypeofbehaviorwill
continue,ifnotspreadandworsen,ifthisnewstandardwasputinplace.

Consideration of Comments: Project 2010-14.1 BAL-001-1

PowerexCorp.

Tooperateinthemanneryouhavedescribedwouldbeaveryhighriskmethodofoperation.Thedraftingteambelievesthatthe
performanceoftheBAswouldnotbecomeworsebutwouldinfactbebetterifthereifthisstandardwasenforceableandthere
werecompliancepenaltiesinvolved.

Thedraftingteamwillcontinuetoevaluateresultsfromthefieldtrialuntilthisstandardhasbecomeeffective.

Response:Thankyouforyourcomment.BAALwasdesignedtoprovideforbettercontrolbyallowingpowerflowsthatdonot
haveadetrimentaleffectonreliabilitybutrestrictthosethatdohaveadetrimentaleffectonreliability

Organization

YesorNo

Question5Comment

48

AlsoofconcernisthedramaticimpactthattheproposedBAALlimitwillhaveonthe
frequencyerroroftheInterconnections.InWECCspecifically,ithasbeenshownthat
thefrequencyerrorhasbeensteadilyincreasingsincethestartoftheRBCfieldtrial.
AsthedraftingteamhaspointedoutintheBackgroundDocumentforthisproposed
standard,reliabilityisreducedwhenInterconnectionfrequencyismovedfarther
fromthescheduledvalue.InlightofthefactthatreplacingCPS2withtheproposed
BAALlimithasalreadybeenshowntohavetheeffectofmovingthefrequencyaway

Anotherconcernisthattherequirementwillallowunlimitedunscheduledflow,
acrossintertieswhentheactualsystemfrequencyisclosetothescheduled
frequency.Thereseemstobeadisregardforthefactthatunscheduledflowscan
haveasignificantdetrimentalimpactonscheduledflows.Curtailmentstoscheduled
flowsisoneofthemaintoolsusedtokeepthesystemoperatingwithinlimitsduring
periodofhighunscheduledflows,effectivelygivingunscheduledflowspriorityaccess
overtherightspaidforbyOATTcustomers(scheduledflows).Forexample,during
theRBCtrialintheWest,thenumberofcurtailmentstoeͲtagswentupdramatically
asaresultofunscheduledflowsacrosspath36,asreportedbytheWECC
PerformanceWorkgroupintheDecember2011QuarterlyReportontheRBCField
Trial.Mostrecently,wehaveseenarecordnumberofcurtailmentsacrosspath66.In
2011therewereatotalof61UnscheduledFlowMitigationeventsforPath66ofStep
4orhigher(seetheWECCUSFMitiagationProcedure).Sofarin2012therehave
alreadybeen741eventsofstep4orhighter.Itisaseriousconcernthattheincrease
inunscheduledflowacrosspath66canbeattributedtothetheRBCfieldtrial(i.e.the
BAALlimit).Iftheproposedstandardisapproveditshouldbeexpectedthatthisissue
willcontinue,andperhapsspreadtootherpartsofthegrid.(Wediscussthisissuein
moredetailinourresponsetoQuestion11.)

PowerexnotesthatnotechnicaljustificationhasbeenputforwardastowhyaBAA
shouldbeabletooperateoutsidetheBAALlimitfor30minutes.Werecommendthat
thedraftingteamconsiderashorterperiod(e.g.5minutes).Aswell,topreventthe
sawtoothingbehavior,Powerexrecommendsthatamonthlymaximumbesetonthe
numberoftimesaBAAcanexceedtheBAALlimit(e.g.5timespermonth).

Consideration of Comments: Project 2010-14.1 BAL-001-1

Organization

YesorNo

Wewouldalsoliketonotethat,undertheWECCfieldtrial,BAsthatareoperating
withBAALhavebeenrequestedbytheReliabilityCoordinatortofurtherlimittheir
ACEduetotransmissionoverloadissuesintheInterconnectioncausedbythe
operationsofanotherBA(e.g.BA#1isinterconnectedwithBA#2,andBA#1’s
inadvertentflowscauseanSOLviolationattheinterconnectionbetweenBA#2and
BA#3,sotheRCrequestsBA#2tochangetheiroperation).Thisshouldbeaserious
concern:ABAoperatingincompliancewiththeproposedBALͲ001reliabilitystandard
(duringtheRBCfieldtrial)iscausingorcontributingtoaviolationofanother
reliabilitystandard(TOP)andpotentiallycausinganotherentitytobeinviolation.

fromthescheduledfrequencyvalue,theadoptionofproposedstandardwouldhave
theoveralleffectofreducingreliability.

Question5Comment

AECI

49

AECIwouldliketorequestamodificationtoAttachment2,suchthatthethis
calculationusesthescheduledfrequencyandnotaconstantof60.0.Suchthatthe

Consideration of Comments: Project 2010-14.1 BAL-001-1

No

ThedraftingteamacknowledgesthatthefrequencybandhasincreasedbutitisstillwithintheFTLthathasbeenselectedforthe
Interconnection.Inaddition,thedraftingteamhasnotseenanyanalysisdonethatwouldprovideinformationpointingtotheuse
ofBAALandtheviolationsyouaredescribing.

TherehavenotbeenanyreliabilityissuesraisedbyanyRCduringthesecalls.ThedraftingteamencouragesBA’sandRC’sto
shareanyspecificoccurrencesthattheyfeelhavereliabilityimpactsasaresultofoperatingunderBAAL. BAALwasdesignedto
provideforbettercontrolbyallowingpowerflowsthatdonothaveadetrimentaleffectonreliabilitybutrestrictthosethatdo
haveadetrimentaleffectonreliability.

BAALwasdesignedtoprovideforbettercontrolbyallowingpowerflowsthatdonothaveadetrimentaleffectonreliabilitybut
restrictthosethatdohaveadetrimentaleffectonreliability.

Thedraftingteamchose30minutestobeconsistentwithotherNERCstandards.

Response:Thankyouforyourcomment.Tooperateinthemanneryouhavedescribedwouldbeaveryhighriskmethodof
operation.ThedraftingteambelievesthattheperformanceoftheBAswouldnotbecomeworsebutwouldinfactbebetterif
thereifthisstandardwasenforceableandtherewerecompliancepenaltiesinvolved.

Organization

YesorNo
BAALcalculationwilladjustfortimeerrorcorrect.

Question5Comment

No

WhileIagreewiththetheoryofBAAL,andthe30minutelimit,theBAALcalculation
needstoaddressthefactthattheBAALforsmallBAscanbemorerestrictivethan
thecurrentCPS2.

No

Additionally,wecontinuetohavereliabilityconcernswiththeBAALlimitsnot
accountingforlargeACEexcursionsandthepossibilityforanincreaseintransmission
limitexceedencesassociatedwithsuchoperation.WebelievetheInterconnection
willbefurtherexposedduetothelackofACEboundingtosomehowreflect
transmissionlimits,andcontinuetobelievethatCPS2isamorereliablemetric.

WeareconcernedthatCPS1alonewillnotaddressadequatelythetimeofdayshort
termfrequencyexcursionsobservedontheEasternInterconnection.

Webelievethatthefrequencymodelanditsuseof3*Epsilonforfrequencytrigger
limitshassignificantshortcomings.Thelevelofreliabilitytargetedandachievedisa
functionofunderfrequencyrelaysettings,interconnectionfrequencyresponse,and
thesizeandexpectedoutagerateofthedesigncontingency(s)forwhichprotectionis
needed.3*Epsilonisnotsensitivetothesevaluesorchangesinthemovertime.Itis
notcoordinatedwiththemodelintheFrequencyResponseStandardunder
development,whichdoesaddressthesesensitivities.

Consideration of Comments: Project 2010-14.1 BAL-001-1

50

Response:Thankyouforyourcomment.Thedraftingteamhasconsideredotheralternativeapproachesandhasselectedthe3
epsilonmodelasthebestandfairestmodelfortherequirement.

ISONewEnglandInc

Response:Thankyouforyourcomment.Thedraftingteamisawareoftheconcernyouhaveidentified.However,thedrafting
teamisattemptingtodevelopastandardthatwouldbeapplicabletotheentirecontinentanddoesnotknowofanymethodto
distinguishbetweenlargerandsmallerBAs.

TucsonElectricPower

Response:Thankyouforyourcomment.Thedraftingteamagreesandhasmadethenecessarymodifications.

Organization

YesorNo

Question5Comment

No

TheeliminationofCPS2hasadetrimentalimpactonreliabilitybecausetheamount
ofunscheduledinterchangeaBAcanhaveisnotcappedwhenfrequencyisinthe
“opposite”direction.Thiscanleadtotransmissionconstraints.TOPsandRCsmust
haveamechanismtorestricttheunscheduledflowsonthesystemduetoaBA
unilaterallyoverorundergenerating.Ibelievetheoldpoliciesstatedthisasthe
intentofCPS2(atleastitwasforA2).Thestandardisdefectiveaswritten.

No

WhileTALagreeswiththeconceptoftheproposedlanguage,thechangeinthe
measurementtimefromBALͲ001Ͳ0.1a,whichwasamonthlymeasure,toa30Ͳ
minutemeasureistroublesome.Eachinstanceofexceeding30minuteswouldbea
violation.Thismayrequirechangestounitresponsesthathavenotbeenaproblem
inthepastduetotheaveragingofunitresponseoveramonthperiod.

No

51

HowwillthisrequirementbeevaluatedwhentheBAdeclaresanEEA?

ERCOTcurrentlyhasawaiverforCPS2compliance.WiththisnewBAALrequirement,
thewaivermaynolongerbeneeded,butthisneedstobeevaluatedfurther.

Consideration of Comments: Project 2010-14.1 BAL-001-1

TexasReliabilityEntity

Response:Thankyouforyourcomment.Thedraftingteamunderstandsthatthe30minutetimeframemayrequiremoreunit
responsebutthedraftingteambelievesthatthe30minrequirementisappropriate.BAALwasdesignedtoprovideforbetter
controlbyallowingpowerflowsthatdonothaveadetrimentaleffectonreliabilitybutrestrictthosethatdohaveadetrimental
effectonreliability.

CityofTallahassee

Response:Thankyouforyourcomment.ThedraftingteambelievesthatneitherBAALnorCPS2guaranteesthataBAwhose
generationisinadirectionthatsupportsinterconnectionfrequencywillnotresultintransmissionissues.BAswithlargeACE
duringperiodswhentransmissionissuesarepresentshouldbeaddressedbytheRC.

NPPD

Thedraftingteamhasnotseenanyissuesthatyouaredescribingoccurduringthefieldtrialthatcanbedirectlyattributableto
theuseofBAAL.BAALwasdesignedtoprovideforbettercontrolbyallowingpowerflowsthatdonothaveadetrimentaleffect
onreliabilitybutrestrictthosethatdohaveadetrimentaleffectonreliability.

Thedraftingteamhasnotseenanyissuesconcerningthe“timeofdayshorttermfrequencyexcursions”duringthefieldtrial.

Organization

YesorNo
Howwillthisrequirementbeevaluatedifthereisagenerationlosseventgreater
thantheMSSC?

Question5Comment

No

52

WhilethecalculationofACEperformanceanditsimpactonfrequencyisapositive
goal,theBAALcalculation,initscurrentform,doesnotaccomplishthis.Sincethe
BAALmeasureiscomparingcurrentACEvaluesagainstacalculatedaverage
frequencyvalue,theBAALmeasureinherentlyallowsforBAALtosignalACE
correctionsintheoppositedirectionofcurrentfrequency,andcanandwillpenalize
BalancingAuthorities(throughnegativeBAALandCPSperformance)forrealͲtime
ACEvaluesthatexceedBAALlimits,evenwhiletheyaresupportingcurrentsystem
frequency.InordertoaccomplishtheintendedgoalsoftherequirementͲtolimit
ACEdeviationswhileconsideringtheirimpactonfrequencyͲ,theBAALmeasure
needstomeasurecurrentactualACEvaluesagainstcurrentactualfrequencyvalues
atthescanrateutilizedforACE/CPScalculation.Furthermore,thetriggerforwhen
eitherBAALLOWorBAALHIGHisusedformeasureisbasedonactualfrequency,
settingupathreepartdisagreementinwhichfrequencymeasureisused.For
example,anActualFrequency(asinRealTime,notaveraged)of60.1isusedto
triggerBAALHIGH,whichwouldthenmeasureperformanceagainsttheprevious
minuteaveragefrequency,whichcouldbebelow60Hz,demonstratingthatthe
measureisnotdesignedtoaccomplishitsspecifiedgoals.Thepurposestatementalso
seemsslightlyoffbase.TheintentionofBAALappearstoprovideameasurable
boundaryforACEperformance,withFrequencytakenintoconsideration,ratherthan
simplyasamechanismtosupportsystemfrequency,whichseemstobethespecific
focusoftheCPS1criteria.Thepurposestatementshouldmoreclearlyreflectthe

Consideration of Comments: Project 2010-14.1 BAL-001-1

ConstellationEnergyControl
andDispatch,LLC

Therequirementwouldbeevaluatedinthesamemannerthatitisevaluatedwhenthereisnogenerationloss.Thedraftingteam
hasnotseenanyissuesthatyouaredescribingoccurduringthefieldtrialthatcanbedirectlyattributabletotheuseofBAAL.

ThedraftingteambelievesthatEEA’spresentlydonotprovideforexclusionfromotherstandardsthatareineffect.

Response:Thankyouforyourcomment.Thedraftingteamunderstandsyourconcernaboutthewaiver.However,thedrafting
teambelievesthatthisisanissuethatshouldbeaddressedbytheapplicableentity.

Organization

YesorNo
actualintentofR2,aswellasthatofR1.

Question5Comment

No

Additionally,thelanguageintherequirementneedstoinsomewayaddresstheissue
ofclockminuteaveragethataredeterminedtobeinvaliddotoissueswiththe
measurementequipment,especiallyifthemeasurementequipmenthasanissue
aroundtheendofa30minuteexceedance.

Thelastphrase“tosupportinterconnectionfrequency”makestherequirement
unclear.Pleasedeletethatphrasesotherequirementisclearandconcise.

Yes

53

Conceptually,weareincompleteagreementwiththeBAALlimit.Itisfarsuperiorto
theCPS2requirements.TheBAALlimitsconsiderfrequencyimpactwhereasCPS2
doesnot.Attimes,CPS2forcesaBAtomoveitsACEinadirectionthatdoesnot
supportfrequency.Furthermore,controlforCPS2couldbeturnedofffor10%ofthe
time(overamonth)andaBAcouldstillbecompliant.Whileweagreewiththe
requirement,somefurtherclarificationisrequiredregardingtheexclusionofoneͲ
minutesamplesasexplainedinAttachment2.Sinceaviolationisbasedon
consecutiveclockminutes,whatshouldtheresponsibleentityassumeaboutclockͲ
minutesamplesthatareexcludedbecauselessthan50%ofthedataisavailableper
Attachment2?IfresponsibleentityisexceedingaBAALhighlimitfor10minutes,
thenfailstorecordthenext8clockͲminutesamplesbecauseofdataunavailability,
andthenexceedsthesameBAALhighlimitforthefollowing13minutes,isthisa
violation?

Consideration of Comments: Project 2010-14.1 BAL-001-1

ACESPowerMarketing
StandardsCollaborators

Thereislanguageintheattachmenttoprovideforinstanceswhenmeasuringequipmentareinoperable.

Response:Thankyouforyourcomment.Thedraftingteamagreesandhasmadethenecessarymodifications.

XcelEnergy

Response:Thankyouforyourcomment.ThedraftingteambelievesthatthereappearstobeamisunderstandingofhowBAALis
calculated.BAALcalculationsuseactualfrequency,actualACEanddoesprovideamechanismtosupportsystemfrequencyasyou
suggest.

Organization

YesorNo

Question5Comment

Yes

Thereferenceto‘it’shouldspecifytheBalancingAuthorityforclarity.

Yes

TheNSRFsupportsR2asanimprovedapproachoverCPS2.Whilenotunderthe
purviewofthisdraftingteam,theproposedchangesinBALͲ003withregardto
variablebias(noflooronvariablebias)openstheopportunityforgamingR2.

Yes

TheSERCOCStandardsReviewGroupisconcernedthatthereliabilityimpactof
violatingthisrequirementisproportionaltothesizeofthebalancingauthority.For
example,PJM,atasizeofover100,000MWhasamuchmoreimpactonreliability
thanSEPA,atlessthan2000MW.WedonotunderstandhowtoapplyVRFs
consistently.ThismayrequiresplittingintomultipleVRFsconsideringthesizeofthe
BA.

Yes

NVEnergy

54

WhileIgeneratllyagreewiththeintentorR2,it'stoowordy.Isuggest"Each

LGEandKUServicesisaparticipantintheBAALFieldTestandsupportthe
implementationoftheBAALstandard.

Consideration of Comments: Project 2010-14.1 BAL-001-1

Yes

Response:Thankyouforyourcomment.

LG&EandKUServices

Response:Thankyouforyourcomment.Thedraftingteamisawareoftheconcernyouhaveidentified.However,thedrafting
teamisattemptingtodevelopastandardthatwouldbeapplicabletotheentirecontinentanddoesnotknowofanymethodto
distinguishbetweenlargerandsmallerBAs.

SERCOCStandardsReview
Group

Response:Thankyouforyourcomment.ThelatestdevelopmentsinBALͲ003provideminimumvaluesforFrequencyBiassettings
whenvariablebiasisusedinmultiͲBAinterconnections.

MRONSRF

Response:Thankyouforyourcomment.Thedraftingteamagreesandhasmadethenecessarymodifications.

ManitobaHydro

Response:Thankyouforyourcomment.Thereislanguageintheattachmenttoprovideforinstanceswhenmeasuringequipment
areinoperable.

Organization

YesorNo

BalancingAuthorityshalloperatesuchthatitsclockͲminuteaverageReportingACE
doesnotexceed,formorethan30consecutiveclockͲminutes,itsclockͲminuteBAAL
[BAALisadefinedterm]fortheapplicableInterconnectioninwhichitoperates.The
BAALequationsaredetailedinAttachment2."

Question5Comment

Yes

SouthCarolinaElectricandGassupportsthecommentssubmittedbytheSERCOC
StandardsReviewGroup.

Yes

Seecommenttoquestion1ontheuseofReportingACE.

Yes
Yes

Yes

Yes
Yes

KeenResourcesAsiaLtd.

IndependentElectricity
SystemOperator

SacramentoMunicipalUtility
District

IdahoPowerCompany

AmericanWindEnergy













Consideration of Comments: Project 2010-14.1 BAL-001-1

Yes

SouthernCompany

55

Response:Thankyouforyourcomment.PleaserefertoourresponsetothecommentssubmittedforQuestion1.

DukeEnergy

Response:Thankyouforyourcomment.PleaserefertoourresponsetothecommentssubmittedbytheSERCOCStandards
ReviewGroup.

SouthCarolinaElectricand
Gas

Response:Thedraftingteamthanksyouforyourcommentbutthedraftingteamhaselectedtonotuseyoursuggestedwording
basedonthecommentsreceivedfromtheindustry.

Organization

Yes
Yes

TacomaPower

ISO'sStandardsReview
Committee








Consideration of Comments: Project 2010-14.1 BAL-001-1




Yes

YesorNo

AmericanElectricPower

Association

Organization

Question5Comment

56






No

YesorNo

No

SeecommentstoNo.5above.

Consideration of Comments: Project 2010-14.1 BAL-001-1

Response:Thankyouforyourcomment.PleaserefertoourresponsetoQuestion5.

SERCOCStandardsReview
Group

57

AECIconcurswiththeconcernsexpressedbySERConbehalfofsmallerBAs.

Question6Comment

Response:Thankyouforyourcomment.PleaserefertoourresponsetothecommentssubmittedbySERC.

AssociatedElectric
CooperativeInc,JRO00088

Organization



Anothercommenterthoughtthe“medium”VRFwasexcessiveandquotedthefirstsentenceoftheVRFguideline.Thedraftingteam
explainedthattheyhadonlyprovidedthefirstsentenceoftheVRFGuidelineforamediumVRF.Thesecondsentence
reads“…However,violationofamediumriskrequirementisunlikelytoleadtobulkelectricsysteminstability,
separation,orcascadingfailures;or,arequirementinaplanningtimeframethat,ifviolated,could,underemergency,
abnormal,orrestorativeconditionsanticipatedbythepreparations,directlyandadverselyaffecttheelectricalstateor
capabilityofthebulkelectricsystem,ortheabilitytoeffectivelymonitor,control,orrestorethebulkelectricsystem.”
ThisisthesentencethatthedraftingteammakesthisamediumVRF.Inaddition,thecurrentapprovedVRFforthis
requirementinBALͲ001Ͳ0.1aisalsoamediumVRF.

OnecommentersuggestedthattheVRFbebasedontheimpactthattheBAhasontheinterconnection.Thedraftingteamstated
thattheywereattemptingtodevelopastandardthatwouldbeapplicabletotheentirecontinentanddidnotknowof
anymethodtodistinguishbetweenlargerandsmallerBAs.ThedraftingteamusedthecurrentVRFDevelopment
Guideline.

SummaryConsideration:ThemajorityofthecommentersagreedthattheVRFswereappropriatefortherequirements.

6.TheBARCSDThasdevelopedVRFsfortheproposedRequirementswithinthisstandard.DoyouagreethattheseVRFsare
appropriatelyset?Ifnot,pleaseexplaininthecommentareabelow.

No
No

PowerexCorp.

AECI

VRFsshouldbeadjustedbaseduponthebalancingauthoritiesimpactuponthe
interconnection.

Nocommentatthistime.

Question6Comment

No

ForR1,aVRFofmediumseemsexcessive.Avalue,measuredoverayear,cannot
"directlyaffecttheelectricalstateorthecapabilityoftheBulkElectricSystem".

Yes

TexasReliabilityEntity

Yes



Consideration of Comments: Project 2010-14.1 BAL-001-1

ISO'sStandardsReview
Committee

58

ThereisareferencetoBALͲ003Ͳ1thatappearsmisplacedintheVRF/VSLjustification
document(pleaseverify).



Response:Thankyouforyourcomment.Thishasbeencorrected.

No

SouthCarolinaElectricand
Gas

Response:Thedraftingteamthanksyouforyourcommentbutthedraftingteamdisagrees.Youhaveonlyprovidedthefirst
sentenceoftheVRFGuidelineforamediumVRF.Thesecondsentencereads“…However,violationofamediumriskrequirement
isunlikelytoleadtobulkelectricsysteminstability,separation,orcascadingfailures;or,arequirementinaplanningtimeframe
that,ifviolated,could,underemergency,abnormal,orrestorativeconditionsanticipatedbythepreparations,directlyand
adverselyaffecttheelectricalstateorcapabilityofthebulkelectricsystem,ortheabilitytoeffectivelymonitor,control,orrestore
thebulkelectricsystem.”ThisisthesentencethatthedraftingteammakesthisamediumVRF.Inaddition,thecurrentapproved
VRFforthisrequirementinBALͲ001Ͳ0.1aisalsoamediumVRF.

NVEnergy

Response:Thankyouforyourcomment.Thedraftingteamisattemptingtodevelopastandardthatwouldbeapplicabletothe
entirecontinentanddoesnotknowofanymethodtodistinguishbetweenlargerandsmallerBAs.Thedraftingteamusedthe
currentVRFDevelopmentGuideline.

YesorNo

Organization

Yes
Yes

Yes
Yes
Yes

Yes
Yes
Yes

Yes
Yes
Yes

Yes

MRONSRF

WesternElectricity
CoordinatingCouncil

ManitobaHydro

HydroͲQuébecTransÉnergie

BonnevillePower
Administration

SPPStandardsReviewGroup

MISOStandardsCollaborators

ArizonaPublicService
Company

SouthernCompany

KeenResourcesAsiaLtd.

IndependentElectricity
SystemOperator

SacramentoMunicipalUtility
District



























Consideration of Comments: Project 2010-14.1 BAL-001-1

Yes

YesorNo

ACESPowerMarketing
StandardsCollaborators

Organization

Question6Comment

59

Yes

Yes
Yes
Yes
Yes

Yes

AmericanWindEnergy
Association

AmericanElectricPower

TacomaPower

TucsonElectricPower

ConstellationEnergyControl
andDispatch,LLC

DukeEnergy

















Consideration of Comments: Project 2010-14.1 BAL-001-1





Yes

YesorNo

IdahoPowerCompany

Organization

Question6Comment

60






No

YesorNo

BPAdoesnotagreewiththerequirementsingeneral,andcannotsupportthe
measures.

Question7Comment

No

61

No.AsstatedaboveinourresponsetoQuestion5,becauseofthesignificant
deficienciesofRequirement2,aBAwouldbeabletooperateinawaythatcould
haveasignificantimpactonreliability,forthemajorityofthetime,withoutfacing

Consideration of Comments: Project 2010-14.1 BAL-001-1

PowerexCorp.

Response:Thankyouforyourcomment.Pleaserefertoourresponsetoyourcommentsconcerningtherequirements.

BonnevillePower
Administration

Organization



OnecommenterfeltitwasunclearifthedatarequiredmustbeEMSqualityofifthedatacouldbefromanothersource.Thedrafting
teamstatedthatdataretentionreferenced“scanrate”data.Aslongasanentitycanprovide“scanrate”datait
shouldnotmatterwhereitcomesfrom.ThisisthesamethatispresentlyineffectwithstandardBALͲ001Ͳ0.1a.

AnothercommenterdisagreedwiththemeasuresbecausetheyfeltthattheDataRetentionsectionappearedtoexcludetheuseof
hardcopyfordataretention.Thedraftingteamexplainedthatthemeasuresdonotreferencethedatainput.They
onlyreferencethemethodforprovingcompliance.Thedataretentionreferencesthedatausedforthecalculation
thatneedstoberetained.

Onecommenterdisagreedwiththemeasuresincetheydisagreedwiththerequirement.Theirconcernwaswiththetreatmentof
smallBAs.Thedraftingteamstatedthattheywereawareoftheconcernidentified.However,thedraftingteamis
attemptingtodevelopastandardthatwouldbeapplicabletotheentirecontinentanddoesnotknowofanymethod
todistinguishbetweenlargerandsmallerBAs.

SummaryConsideration:Themajority themajorityofthecommentersagreedthatthemeasureswereappropriateforthe
requirements.


7.TheBARCSDThasdevelopedMeasuresfortheproposedRequirementswithinthisstandard.Doyouagreewiththeproposed
Measuresinthisstandard?Ifnot,pleaseexplaininthecommentarea.

YesorNo
anypenaltyorsanction.

Question7Comment

No

NeedtoaddresstheBAALcalculationforsmallBAs

No

TheproposedM1andM2eachallowforevidenceinhardcopyORelectronicformat.
SectionDitem1.2(DataRetention)seeminglyexcludestheacceptabilityofhardcopy
evidence.TALsuggeststhattheDataRetentionrequirementbeexpandedtoinclude
hardcopyevidencetobeconsistentwithM1andM2.

No

ItisunclearfromthelanguageiftherequireddatamustbeEMSqualityorifthedata
canbefromadatarecordersuchasPI.TheMeasureneedstobeclearonthisissue.

Yes

Yes

AssociatedElectric
CooperativeInc,JRO00088

ACESPowerMarketing







Consideration of Comments: Project 2010-14.1 BAL-001-1

Yes

ISO'sStandardsReview
Committee

62

Response:Thankyouforyourcomment.Thedataretentionreferences“scanrate”data.Aslongasanentitycanprovide“scan
rate”dataitshouldnotmatterwhereitcomesfrom.ThisisthesamethatispresentlyineffectwithstandardBALͲ001Ͳ0.1a.

XcelEnergy

Response:Thankyouforyourcomment.Themeasuresdonotreferencethedatainput.Theyonlyreferencethemethodfor
provingcompliance.Thedataretentionreferencesthedatausedforthecalculationthatneedstoberetained.

CityofTallahassee

Response:Thankyouforyourcomment.Thedraftingteamisawareoftheconcernyouhaveidentified.However,thedrafting
teamisattemptingtodevelopastandardthatwouldbeapplicabletotheentirecontinentanddoesnotknowofanymethodto
distinguishbetweenlargerandsmallerBAs.

TucsonElectricPower

Response:Thankyouforyourcomment.PleaserefertoourresponsetoQuestion5.

Organization

Yes

Yes
Yes
Yes
Yes
Yes

Yes
Yes
Yes

Yes

Yes
Yes

SERCOCStandardsReview
Group

ManitobaHydro

SPPStandardsReviewGroup

MISOStandardsCollaborators

HydroͲQuébecTransÉnergie

ArizonaPublicService
Company

SouthernCompany

KeenResourcesAsiaLtd.

IndependentElectricity
SystemOperator

SacramentoMunicipalUtility
District

AECI

IdahoPowerCompany



























Consideration of Comments: Project 2010-14.1 BAL-001-1

Yes

YesorNo

MRONSRF

StandardsCollaborators

Organization

Question7Comment

63

Yes
Yes
Yes
Yes

Yes
Yes

Yes

AmericanElectricPower

TacomaPower

NVEnergy

SouthCarolinaElectricand
Gas

TexasReliabilityEntity

ConstellationEnergyControl
andDispatch,LLC

DukeEnergy


















Consideration of Comments: Project 2010-14.1 BAL-001-1



Yes

YesorNo

AmericanWindEnergy
Association

Organization

Question7Comment

64






No

YesorNo

No

Question8Comment

Consideration of Comments: Project 2010-14.1 BAL-001-1

65

No.AsstatedaboveinourresponsetoQuestion5,becauseofthesignificant
deficienciesofRequirement2,aBAwouldbeabletooperateinawaythatcould
haveasignificantimpactonreliability,forthemajorityofthetime,withoutfacing
anypenaltyorsanction.

While“reliabilityissues”havenotbeenidentifiedbytheRCs,thereareotherissues
thatneedtobeaddressedthatarenotmentionedinthebackgrounddocument.

Response:PleaserefertoourresponsetoQuestion5.

PowerexCorp.

Response:Thankyouforyourcomment.

ArizonaPublicService
Company

Organization



OnecommenterdisagreedwiththeVSLsandfeltthattheyshouldbegradedbythesizeofentityinlieuofhavingmultipleVRFs.The
draftingteamexplainedthatunderthepresentguidelinesastandardmusthaveaVRFandVSL.TheVRFsaccountfor
theimpacttherequirementcouldhaveontheBESwhiletheVSLaccountsfortheseverityoftheviolationofthe
requirement.ThedraftingteamdoesnotknowofanywaytodifferentiatetheVSLbasedonthesizeofanentity.The
draftingteambelievestodifferentiatebasedonthesizewouldaddalargedegreeofsubjectivitybasedonthe
thresholdsused.

AcoupleofcommentersdisagreedwiththeVSLsbasedontheobjectiontoRequirementR2andthetreatmentofsmallBAs.The
draftingteamstatedthattheywereawareoftheconcernidentified.However,thedraftingteamisattemptingto
developastandardthatwouldbeapplicabletotheentirecontinentanddoesnotknowofanymethodtodistinguish
betweenlargerandsmallerBAs.

SummaryConsideration:ThemajoritythemajorityofthecommentersagreedthattheVSLswereappropriatefortherequirements.

8.TheBARCSDThasdevelopedVSLsfortheproposedRequirementswithinthisstandard.DoyouagreewiththeseVSLs?Ifnot,
pleaseexplaininthecommentarea.

Yes

YesorNo
ThedraftingteammaywanttolookathowsmallBAsareimpactedbyR2.TheCPS
curveforsmallBAshasawidertail.Theperformanceexpectationsmaynotbethe
same.

Question8Comment

Yes

ThedraftingteammaywanttolookathowsmallBAsareimpactedbyR2.TheCPS
curveforsmallBAshasawidertail.Theperformanceexpectationsmaynotbethe
same.

Yes

PerhapsVSLscouldbegradedbythesizeoftheentityinlieuofhavingmultipleVRFs.

Yes

TotheextentthatwebelievetheVSLsareappropriatefortherequirementsas
written.However,theVSLswillpotentiallyneedtobemodifiedifthesuggested
changesareimplemented.

Consideration of Comments: Project 2010-14.1 BAL-001-1

66

Response:Thankyouforyourcomment.Thedraftingteamwillensurethatanymodificationstotherequirementswillbe
reflectedintheVSLs.

WesternElectricity
CoordinatingCouncil

Response:Thankyouforyourcomment.UnderthepresentguidelinesastandardmusthaveaVRFandVSL.TheVRFsaccountfor
theimpacttherequirementcouldhaveontheBESwhiletheVSLaccountsfortheseverityoftheviolationoftherequirement.The
draftingteamdoesnotknowofanywaytodifferentiatetheVSLbasedonthesizeofanentity.Thedraftingteambelievesto
differentiatebasedonthesizewouldaddalargedegreeofsubjectivitybasedonthethresholdsused.

SERCOCStandardsReview
Group

Response:Thankyouforyourcomment.Thedraftingteamisawareoftheconcernyouhaveidentified.However,thedrafting
teamisattemptingtodevelopastandardthatwouldbeapplicabletotheentirecontinentanddoesnotknowofanymethodto
distinguishbetweenlargerandsmallerBAs.

MRONSRF

Response:Thankyouforyourcomment.Thedraftingteamisawareoftheconcernyouhaveidentified.However,thedrafting
teamisattemptingtodevelopastandardthatwouldbeapplicabletotheentirecontinentanddoesnotknowofanymethodto
distinguishbetweenlargerandsmallerBAs.

ISO'sStandardsReview
Committee

Organization

Yes

YesorNo

Yes

Yes

Yes
Yes
Yes
Yes
Yes
Yes

Yes

Yes

ACESPowerMarketing
StandardsCollaborators

BonnevillePower
Administration

SPPStandardsReviewGroup

MISOStandardsCollaborators

SouthernCompany

ManitobaHydro

KeenResourcesAsiaLtd.

IndependentElectricity
SystemOperator

SacramentoMunicipalUtility
District

AECI























Consideration of Comments: Project 2010-14.1 BAL-001-1

Yes

AssociatedElectric
CooperativeInc,JRO00088

67

SouthCarolinaElectricandGassupportsthecommentssubmittedbytheSERCOC
StandardsReviewGroup

Question8Comment

Response:PleaserefertoourresponsetocommentssubmittedbytheSERCOCStandardsReviewGroup.

SouthCarolinaElectricand
Gas

Organization

Yes

Yes
Yes
Yes
Yes
Yes
Yes
Yes

Yes

AmericanWindEnergy
Association

HydroͲQuébecTransÉnergie

AmericanElectricPower

TacomaPower

TucsonElectricPower

NVEnergy

TexasReliabilityEntity

ConstellationEnergyControl
andDispatch,LLC

DukeEnergy























Consideration of Comments: Project 2010-14.1 BAL-001-1





Yes

YesorNo

IdahoPowerCompany

Organization

Question8Comment

68




No

YesorNo

Question9Comment

69

2)Whileitisnotmaterialtothenewstandard,theA1criteriaisnotproperlystated.
UnderA1,ACEneededtocrosszeroatleastonceineverytenminuteperiodofthe
hourandthatthetotalnonͲcrossingshadtobelessthan10percentofallperiods.

1)Ifthebackgrounddocumentisexpectedtobeusedjusttoexplaintheteam’s
work,wehavenoissuewithit.IfitisexpectedtoreplacethecurrentPerformance
StandardsReferenceGuidelinesintheNERCOperatingManual,thedocumentlacks
significantdetail.

Consideration of Comments: Project 2010-14.1 BAL-001-1

ISO'sStandardsReview
Committee

Organization



AcoupleofcommentersfeltthattheBackgroundDocumentprovidedvaluablematerialandthatitshouldberetained.Thedrafting
teamagreedandstatedthattheywouldrecommendthatNERCkeepthedocumentontheirwebsite.

AfewcommentersmentionedthattherewasanerrorinthedescriptionofA1criterialocatedintheBackgroundDocument.The
draftingteamagreedwiththecommenterandmodifiedthedocumenttoreflectthecorrectlanguage.

Somecommentersdisagreedwiththestatementmadebythedraftingteamthattherehasnotbeenanyreliabilityissuesoccur
duringthefieldtrial.ThedraftingteamexplainedthattherehavenotbeenanyreliabilityissuesraisedbyanyRC
duringthemonthlycalls.ThedraftingteamencouragesBA’sandRC’stoshareanyspecificoccurrencesthattheyfeel
havereliabilityimpactsasaresultofoperatingunderBAAL.

SummaryConsideration:SeveralcommenterswantedthefieldtrialdataincludedintheBackgroundDocument.Thedraftingteam
statedthattheyconductamonthlycalltodiscussthepriormonthoperationusingBAAL.Thesemonthlyresultsare
postedontheNERCwebsite.TheBAALfieldtrialwillcontinueineffectuntilthedatethatanewstandardgoesinto
effect.ThedraftingteamwillbepreparingareportbasedonthefieldtrialresultsthatwillbepostedpriortotheFERC
filingforthisdraftstandard.


9.TheBARCSDThasdevelopedadocument“BALͲ001Ͳ1RealPowerBalancingControlStandardBackgroundDocument”which
providesinformationbehindthedevelopmentofthestandard.Doyouagreethatthisnewdocumentprovidessufficientclarityas
tothedevelopmentofthestandard?Ifnot,pleaseexplaininthecommentarea.

YesorNo

Question9Comment

No

Whileitisnotmaterialtothenewstandard,theA1criterionisnotproperlystated.
UnderA1,ACEneededtocrosszeroatleastonceineverytenminuteperiodofthe
hourandthatthetotalnonͲcrossingshadtobelessthan10percentofallperiods.

No

ThebackgrounddocumentshouldincludetheFieldTrialresultsfromall
Interconnections.

No

BPAdisagreeswiththeargumentthatCPS2islessreliablebecauseyoucanbeoutof
boundsfor72hourspermonth.TakingthesameargumenttoRBC,onecanbeoutof
bounds29minutes,backinforaminuteandoutofboundsfor29minutes.This
equatesto696hourspermonth.BPAbelievesithasbeendemonstrated,atleastin
WECC,thatCPS2ismorereliable.BPAhasyettodetermineifthedecreasein
reliabilityisworththeincreaseinflexibilitythatRBCallows.

Thedocumentmentionsthattherehasbeennoreliabilityissueswiththefieldtrial.
BPAandothersinWECChaveexperiencedmanySOLviolationsduetoLargeACEs.

Consideration of Comments: Project 2010-14.1 BAL-001-1

70

Response:Thankyouforyourcomment.ThedraftingteamconductsamonthlycalltoreviewtheresultsfromtheBAALfieldtrial.
TherehavenotbeenanyreliabilityissuesraisedbyanyRCduringthesecalls.ThedraftingteamencouragesBA’sandRC’sto

BonnevillePower
Administration

Response:Thankyouforyourcomment.Thedraftingteamconductsamonthlycalltodiscussthepriormonthoperationusing
BAAL.ThesemonthlyresultsarepostedontheNERCwebsite.TheBAALfieldtrialwillcontinueineffectuntilthedatethatanew
standardgoesintoeffect.Thedraftingteamwillbepreparingareportbasedonthefieldtrialresultsthatwillbepostedpriorto
theFERCfilingforthisdraftstandard.

WesternElectricity
CoordinatingCouncil

Response:Thankyouforyourcomment.Thiswillbecorrected.

MRONSRF

2)Thankyouandthiswillbecorrected.

1)Thedraftingteamdoesnotintendforthisdocumenttoreplaceanything.Thedocumentwasonlyintendedtoprovideinsight
intothedraftingteamsthoughtprocessduringthedevelopmentofthisstandard.

Response:Thankyouforyourcomment.

Organization

YesorNo

Question9Comment

No

Whiletheyarenotmaterialtothenewstandard,theA1criteriaarenotproperly
stated.UnderA1,ACEneededtocrosszeroatleastonceineverytenminuteperiod
ofthehourandthetotalnonͲcrossingshadtobelessthan10percentofallperiods.

No

ConclusiveresultsoftheBAALfieldtrialarenotprovidedinthebackground
document.IftheindustryistomakethemovetomakethechangefromCPS2to
BAALs,thereshouldbeevidenceprovidedthatthisactionwillaidinbetterfrequency
controlfortheInterconnections.

No

71

No.Inparticularthissentenceonpage5ofthebackgrounddocumentprovidesno
technicaljustificationforthethe"3"intheplus/minus3epsilonFTL:"BAALwas
derivedbasedonreliabilitystudiesandanalysiswhichdefinedaFrequencyTrigger
Limit(FTL)boundmeasuredinHz."TheanalysiscommissionedbyNERCwithout
tendertoanoutsidesoftwarevendorwasdemolishedintheextensiveposted
commentsby2statisticalexperts,CaliforniaISOandNPCC.Theanalysiswasjunked
togetherwiththerejectedproposedstandardasNERCproceededtoformanew
draftingteamtorebuildthestandard.3hasbeendemonstratedthroughoutthefield
testtobetootightintermsofgeneratingtoomanyBAALexceedencestobe
addressedimmediatelybytheBA.TheBAneedstowaitatleast5minutesfor

Consideration of Comments: Project 2010-14.1 BAL-001-1

KeenResourcesAsiaLtd.

Response:Thankyouforyourcomment.Thedraftingteamconductsamonthlycalltodiscussthepriormonthoperationusing
BAAL.ThesemonthlyresultsarepostedontheNERCwebsite.TheBAALfieldtrialwillcontinueineffectuntilthedatethatanew
standardgoesintoeffect.Thedraftingteamwillbepreparingareportbasedonthefieldtrialresultsthatwillbepostedpriorto
theFERCfilingforthisdraftstandard.

ProgressEnergy

Response:Thankyouforyourcomment.Thiswillbecorrected.

MISOStandardsCollaborators

TheBackgroundDocumentdoesnotaddresstherelativereliabilityofCPS2versusBAAL.The72hoursthataBAcouldbeoutside
theCPS2andbefullycompliantwasanobservationandnotanimplicationofreliability.Thedraftingteambelievesthat
operatingtothelimitsofanymeasureisanextremelyhighriskoperation.

shareanyspecificoccurrencesthattheyfeelhavereliabilityimpactsasaresultofoperatingunderBAAL.

Organization

YesorNo

enoughoftheseexceedencestogoawaytoleaveafeasible/manageablenumber
begintoaddressing.Suchwaitingjeopardizesreliability.Itismuchmoreprudentto
raisethe"3"tosomewherebetween4or5togenerateexceedencessmallenoughin
numbertobefeasible/manageabletobeginaddressingimmediatelyupon
occurrence.SettingtheFTLatahighenoughthresholdwherethenumberof
exceedencesbecomesfeasibleormanageableenoughtobeaddressedimmediately
uponoccurrenceinsteadof5ormoreminutesaftertheyhavebegunifFTLissetat
toolowamultipleofepsilon,isleastexpensiveandmostfavorabletoreliability.The
fieldtesthasnot"proved"that3isthepropermultiplejustbecausetherehasbeen
noblackout.Otherwisewecangohomeuntilthenextblackout.Insteadthefield
testhasproducedthedatasupportingthecontentionthatthelimitistootightfor
reliabilitybecauseitgeneratestoomanyshortͲlivedexceedencesandthereby
encourageswaitingtoaddresstheexceedencesthatwillpersistandbeveryserious.
Afterthedemiseofthepreviousproposedstandard,NERCelectedtochangepolicy
andstopcommissioningresearchandthereforedevelopmentofanythorough
technicaljustificationforthepresentproposedstandard.Inotherwords,NERCcan
nolongerjustifyareliabilitystandardbyanydocumentedscientificprocedureofits
own.

Question9Comment

No

Consideration of Comments: Project 2010-14.1 BAL-001-1

72

Whileitisnotmaterialtothenewstandard,theA1criterionisnotproperlystated.
UnderA1,ACEneededtocrosszeroatleastonceineverytenminuteperiodofthe
hourandthatthetotalnonͲcrossingshadtobelessthan10percentofallperiods.

Response:Thankyouforyourcomment.Thiswillbecorrected.

IndependentElectricity
SystemOperator

ThedraftingteamconductsamonthlycalltoreviewtheresultsfromtheBAALfieldtrial.Therehavenotbeenanyreliability
issuesraisedbyanyRCduringthesecalls.ThedraftingteamencouragesBA’sandRC’stoshareanyspecificoccurrencesthatthey
feelhavereliabilityimpactsasaresultofoperatingunderBAAL.

Response:Thankyouforyourcomment.Thedraftingteamhasconsideredotheralternativeapproachesandhasselectedthe3
epsilonmodelasthebestandfairestmodelfortherequirement.

Organization

No

PowerexCorp.

BAsoperatingoutsidetheBAALlimitinacyclicalmanner,thedetrimentalimpactof
unscheduledflowsonthegrid,andtheincreaseinfrequencyerror.

No.PowerexfeelstheBackgroundDocumentdoesnotreferenceorexplainanyof
thefindingsoftheRBCtrialdiscussedinQuestion5thatshouldbeofconcern,i.e.

Question9Comment

No

WhileIagreeoverallwiththebackgrounddocument,therehavebeensome
transmissionflowissuesreportedfromtheWesternInterconnectionRCs.Tomakea
statementthattherehavebeennoreportedreliabilityissuesmaynotbeentirely
correct.IagreethatBAALhasamorepositiveeffectoninterconnectionfrequency
thandoesCPS2.BAALwithsomesortoftransmissionlimitmightbethewaytogo.

No

GiventherampantneedintheindustryforRequestsforInterpretations,Rapid
Revisions,andCANs,webelievethatfutureStandardsneedtobewrittensothatthey
can"standalone"uponscrutiny.

Consideration of Comments: Project 2010-14.1 BAL-001-1

73

Response:Thankyouforyourcomment.ThedraftingteambelievesthatthisisaNERCStandardsProcessissueandistherefore
outsidethescopeofthisproject.However,thedraftstandardsareevaluatedbyindividualstrainedtoperformqualityreviews.
Thedraftingteambelievesthatifthisstandardwasnotabletostandonitsown,itwouldbeidentifiedduringthequalityreview

ISONewEnglandInc

Response:Thankyouforyourcomment.Thedraftingteamunderstandsthattherehasbeensometransmissionflowissues
reportedthatarepresentlybeinginvestigatedbytheWECCPerformanceWorkingGroup.However,therehavenotbeenany
reliabilityissuesraisedbyanyRCduringthesecalls.ThedraftingteamencouragesBA’sandRC’stoshareanyspecificoccurrences
thattheyfeelhavereliabilityimpactsasaresultofoperatingunderBAAL.

TucsonElectricPower

TherehavenotbeenanyreliabilityissuesraisedbyanyRCduringthesecalls.ThedraftingteamencouragesBA’sandRC’sto
shareanyspecificoccurrencesthattheyfeelhavereliabilityimpactsasaresultofoperatingunderBAAL.

Response:Thankyouforyourcomment.Thedraftingteamconductsamonthlycalltodiscussthepriormonthoperationusing
BAAL.ThesemonthlyresultsarepostedontheNERCwebsite.TheBAALfieldtrialwillcontinueineffectuntilthedatethatanew
standardgoesintoeffect.Thedraftingteamwillbepreparingareportbasedonthefieldtrialresultsthatwillbepostedpriorto
theFERCfilingforthisdraftstandard.

YesorNo

Organization

No

YesorNo

AlthoughTALunderstandsfromthedocument'sIntroductionthatnoreliabilityissues
havebeenidentifiedinthefieldtrial,TALseeksadditionalinformationonthe
challengesencounteredbytheparticipantsduringtheimplementationandfieldtrial.
TALalsoseeksgreaterexplanationofthefieldtrialresults.

Question9Comment

No

XcelEnergyrecommendsthattheBackgroundDocumentrefertoandprovidealink
tothedataandrelatedevaluationsthathasbeencollectedovertheyearsofthefield
trial.

Yes

ThebackgrounddocumentprovidedwithBALͲ001Ͳ1providedvaluableinformation
regardingthehistoryofcontrolperformancecriteriaandhowtheSDTgottowhereit
istodaywiththeproposedstandard.Whataretheplansforthedocument?Willit
becomeaguideline,referencedocument,etc?Itneedstobemaintainedforfuture
referenceandupdating.

Consideration of Comments: Project 2010-14.1 BAL-001-1

74

Response:Thankyouforyourcomment.Thedraftingteamwillrecommendthatthisdocumentbearchivedinanappropriate
placeforfuturereference.

SPPStandardsReviewGroup

http://www.nerc.com/filez/standards/Reliability_Based_Control_FieldTrial_Tools_2007Ͳ18ͲRF.html

Response:Thankyouforyourcomment.ThedraftingteamdoesnotagreethatalinkisneededfortheBackgroundDocument.
However,thedraftingteamisprovidingalinktothedocumentsbelow.

XcelEnergy

ThedraftingteamconductsamonthlycalltodiscussthepriormonthoperationusingBAAL.Thesemonthlyresultsarepostedon
theNERCwebsite.TheBAALfieldtrialwillcontinueineffectuntilthedatethatanewstandardgoesintoeffect.Thedrafting
teamwillbepreparingareportbasedonthefieldtrialresultsthatwillbepostedpriortotheFERCfilingforthisdraftstandard.

Response:Thankyouforyourcomment.Thedraftingteamisunsureofthetypeofadditionalinformationyouareseeking.We
encourageyoutocontactthoseparticipatinginthefieldtrialtoseektheirfeedbackonanyoperationalissuesencounteredduring
thefieldtrial.

CityofTallahassee

process.

Organization

Yes

YesorNo

Yes

Seecommentforitem5,relatedtoR2.IfthecalculationindicatedforR2isnot
successfulinmeetingtheintentofthestandard,thenthemeasureswouldbe
similarlyproblematic.

Yes,providesclaritybutthereremainsdisagreementwiththerationale.

Question9Comment

Yes

Yes



Consideration of Comments: Project 2010-14.1 BAL-001-1

AssociatedElectric
CooperativeInc,JRO00088

75

Onpage5ofthedocument,theSDTleftouttheword“Standard”between
Performanceand2inthefirstparagraphunderthe“BackgroundandRationale”
section.“Significanthours”isnotagooddescriptionforthe72hourspermontha
BA’sACEcanbeoutsideitsL10asitisusedinthelastsentenceofthedocumenton
page6.Itshouldbechangedtosomethingalongthelinesof,“....allowsfora
BalancingAuthority’sACEvaluetobeunboundedforaspecificamountoftime
duringacalendarmonth.”

Thedocumentprovidessufficientclarityastothedevelopmentofthestandard.
Thereisnovalueaddedtothedocument,however,withtheinclusionofthe
“HistoricalSignificance”sectiongoingbackto1973,A1ͲA2ControlPerformance
Criteria,thenleadingupto1996describingtheNERCPolicyCPS1,CPS2,andDCS.
TheSDTsimplyneedstodefineCPS1andCPS2andtheirrationaleforthe
developmentofthestandard.

Response:Thankyouforyourcomment.Thedraftingteamagreesandhasmadethenecessarymodifications.

DukeEnergy

Response:Thankyouforyourcomment.PleaserefertoourresponseforQuestion5.

ConstellationEnergyControl
andDispatch,LLC

Response:Thankyouforyourcomment.

ArizonaPublicService
Company

Organization

Yes
Yes
Yes

Yes
Yes

Yes
Yes
Yes

Yes
Yes
Yes
Yes

HydroͲQuébecTransÉnergie

ManitobaHydro

SERCOCStandardsReview
Group

SouthernCompany

SacramentoMunicipalUtility
District

AECI

IdahoPowerCompany

AmericanWindEnergy
Association

AmericanElectricPower

TacomaPower

NVEnergy

SouthCarolinaElectricand
Gas



























Consideration of Comments: Project 2010-14.1 BAL-001-1



Yes

YesorNo

ACESPowerMarketing
StandardsCollaborators

Organization

Question9Comment

76








YesorNo



Question10Comment

77

InOrderNo.890,theFederalEnergyRegulatoryCommission(FERCorthe
Commission)recognizedthepotentialforunscheduledenergyflowsbetween

Iamnotawareofconflicts.

Consideration of Comments: Project 2010-14.1 BAL-001-1

PowerexCorp.

Response:Thankyouforyourcomment.

NVEnergy

Organization



AnothercommenterwantedtocombineBALͲ001andBALͲ002.Thedraftingteamstatedthattheyhaddiscussedcombiningthe
standardsintoonebutchosetokeepthemseparate.Thedraftingteambelievesthatcombiningthetwostandards
couldcreateadditionalconfusion.Inaddition,thedraftingteambelievesthatitwouldbedifficulttogetindustry
agreement.

OnecommenterdisagreedwithusingthetermReportingACEandthatthiscouldcauseproblemswithotherstandards.Thedrafting
teamexplainedthattheybelievedthatdefininganewterm“reportingACE”wouldallowconsistentevaluationof
individualBAsperformancetoCPS1andBAAL.ThedraftingteamrealizesthatthisdefinitionofreportingACEismore
prescriptive.SinceACEcanvarybetweenBAsaccordingtocontrolalgorithmsthedraftingteamfeltitwasnecessary
todefinereportingACEtoensureuniformity.Thedraftingteamfurtherexplainedthattheydidnotbelievethatthe
proposedstandardwouldcreateanyproblemswithotherstandards.StandardsarewrittentobestandͲalone.Forthis
factalone,thereshouldnotbeanynegativeimpacts.Thedraftingteamhasevaluatedseveralotherstandardsandhas
notfoundanyinstancesofambiguitybeingcreated.

SummaryConsideration:Afewcommentersfeltthatthecurrentversionofthestandardcouldprovideanentitytheopportunityto
cratelargeinadvertentflowsbyoperatingunderBAAL.Thedraftingteamstatedthattheyhadnotseenanyissues
thattheyweredescribingoccurduringthefieldtrialthatcanbedirectlyattributabletotheuseofBAAL.BAALwas
designedtoprovideforbettercontrolbyallowingpowerflowsthatdonothaveadetrimentaleffectonreliabilitybut
restrictthosethatdohaveadetrimentaleffectonreliability.

10.Ifyouareawareofanyconflictsbetweentheproposedstandardandanyregulatoryfunction,ruleorder,tariff,rateschedule,
legislativerequirement,oragreementpleaseidentifytheconflicthere.

YesorNo

adjacentBAAsbothtojeopardizereliabilityandtocauseundueharmtocustomers
onthegrid.TheCommissionstated,atP703,inregardstotheexistingframework
forinadvertentenergy:”However,ifthereisevidencethatitisnolongersufficientto
maintainreliability,orisallowingcertainentitiestoleanonthegridtothedetriment
ofotherentities,theCommissionhasauthorityunderFPAsection215todirectthe
EROtodevelopanewormodifiedstandardtoaddressthematter."Powerex
believesthatthedevelopmentoftheBALͲ001standardbasedonthecurrentpurpose
statementwillallowentitiestocreatedeliberateinadvertentflowswithinthe
standardsboundaries,withoutregardtotheimpacttotransmissioncustomersonthe
grid.Thismayresultinsubstantialcurtailmentstotransmissioncustomersindirect
contraventionoftheCommission’sopenaccesstransmissionprinciplesofOrder
890.BALͲ001mayalsobeinconflictwithFERCOrder693(P397).Inthatorder,the
Commissionnotedthatwhilethecontrolperformancestandardmetric(BAALlimitin
R2)isusefulinidentifyingtrendsrelatingtopoorregulatingpractices,specificationof
minimumreserverequirementstobemaintainedatalltimeswouldcomplementthe
controlperformancestandardmetricsbyprovidingrealͲtimerequirementsnecessary
forpropercontrol.“[T]hecontrolperformancestandardmetricisalaggingindicator
and,assuch,doesnotprovideagoodindicationthatnecessaryamountsof
regulatingreservearebeingcarriedatalltimes.”Thecapabilitytobeabletomeeta
BA’sexpectedintraͲhourimbalances,withasignificantdegreeofconfidence,should
beachievedprospectivelyeachhour.ItisnotsufficienttoreduceaBA’sregulation
toaleveldesignedonlytomeettheperformancestandardsretrospectively.Though
aprospectivebalancingreserverequirementascontemplatedinOrder693maybe
missingfromstandardscurrentlyinplace,theinherentlimitsinthecurrentCPS2are
strictenoughsuchthattheneedforaprospectiveminimumrequirementisreduced.
However,therelaxationofthecontrolperformancemeasuresinBALͲ001makeit
imperativethattheminimumreserverequirementscontemplatedinOrder693are
included.

Question10Comment

Consideration of Comments: Project 2010-14.1 BAL-001-1

78

Response:Thankyouforyourcomment.Thedraftingteamhasnotseenanyissuesthatyouaredescribingoccurduringthefield
trialthatcanbedirectlyattributabletotheuseofBAAL.BAALwasdesignedtoprovideforbettercontrolbyallowingpowerflows

Organization

YesorNo

Question10Comment



InamultipleͲBAInterconnection,theboundsofCPS1andBAALrepresenteachBA’s
shareofresponsibilityinmaintainingfrequencywithindefinedboundsͲtotheextent
thatInterconnectionfrequencyremainswithinacceptablelimits,nonͲcomplianceina
generalsenseismoreofanequityconcern,thanareliabilityissuerisingtothelevel
requiringactionsuptoanincludingthesheddingoffirmloadtoremaincompliant.
UnderwhatcircumstancesshouldtheBalancingAuthorityshedfirmloadasalast
resorttoensurethatitremainscomplianttothe“ControlPerformanceand
DisturbanceControlStandards”?

ItcouldbeinterpretedthatthelanguageinR5ofEOPͲ002Ͳ3conflictswiththeCPS1
andBAALstandards.EOPͲ002Ͳ3R5includesthesentences,“TheBalancingAuthority
shallnotunilaterallyadjustgenerationinanattempttoreturnInterconnection
frequencytonormalbeyondthatsuppliedthroughfrequencybiasactionand
InterchangeSchedulechanges.Suchunilateraladjustmentmayoverload
transmissionfacilities.”AsoperationinsupportofInterconnectionfrequencyunder
CPS1andBAALallowsforsupportbeyondthatsuppliedbyfrequencybiasaction,
DukeEnergybelievesthatthesentencesshouldbetakenoutofEOPͲ002Ͳ3R5,which
wereneverintendedtobeapplicabletothedeficientBalancingAuthorityforwhich
thestandardapplies.ConformingchangeswillalsoneedtobemadetoEOPͲ002Ͳ3R6
whichreferences“ControlPerformanceandDisturbanceControlStandards”.Itcould
beinterpretedfromthelanguageinR6ofEOPͲ002Ͳ3,thataBalancingAuthorityis
consideredinanemergencyconditionandshouldbeimplementingitsemergency
planifitisnotcapableofcomplyingatanytimetotheCPS1,CPS2,BAAL,orDCS
measures.

Consideration of Comments: Project 2010-14.1 BAL-001-1

79

Response:Thankyouforyourcomment.ThedraftingteambelievesthatEOPissuesarebeyondthescopeofthisdraftingteam.
However,thedraftingteamwillpassyouconcernontheappropriateindividualsatNERCforfutureconsideration.

DukeEnergy

ThedraftingteambelievesthatBAALisnotintendedtosolveallissues.Thestandards(BAL)takentogetherandinteracting
togethersolveissues.

thatdonothaveadetrimentaleffectonreliabilitybutrestrictthosethatdohaveadetrimentaleffectonreliability.

Organization

YesorNo

Question10Comment



MISOnotestheuseofcrossͲreferencesandsimilartermsamongandbetween
reliabilitystandards.Accordingly,termsandconceptspreviouslyutilizedinBALͲ001Ͳ
0.1athathavebeenreplaced,modified,orreͲdefinedinBALͲ001Ͳ1mayimpactother
reliabilitystandardssuchasBALͲ003,BALͲ004,andBALͲ005Ͳ0.1b.MISOnotesthat
theuseofcrossͲreferencesandsimilartermsshouldbeevaluatedtoensure
consistencyamongstthereliabilitystandardsandrequirements.Inparticular,where
termsandrequirementshavebeenredefinedormodifiedinBALͲ001Ͳ1,acrossͲ
referencedorcloselyrelatedstandardorrequirementcouldbeimpactedbythe
modificationtoBALͲ001Ͳ1.Forexample,BALͲ005Ͳ0.1breferencesthe“ACE
equation,”whichequationappearstohavebeenreplacedbyanequationtocalculate
ReportingACE.Additionally,thecreationofanewglossarydefinitioncouldresultin
ambiguityregardingrequiredperformanceoutcomesandobligationswherea
previousdefinedtermhadbeenusedandismaintainedincrossͲreferencedorclosely
relatedstandards.Forexample,severalBALstandardsrefertoanduseACEasa
performancestandardorrequirement.Itisunclearwhetherthisperformance
obligationremainstiedtorawACEcalculationsortoanentity’sReportingACE.MISO
respectfullysuggeststhattheBARCSDTperformacomprehensivereviewofBALͲ001Ͳ
1’simpactoncrossͲreferencedorcloselyrelatedreliabilitystandardspriorto
implementation.

Consideration of Comments: Project 2010-14.1 BAL-001-1

80

Thedraftingteamdoesnotbelievethattheproposedstandardwillcreateanyproblemswithotherstandards.Standardsare
writtentobestandͲalone.Forthisfactalone,thereshouldnotbeanynegativeimpacts.Thedraftingteamhasevaluatedseveral
otherstandardsandhasnotfoundanyinstancesofambiguitybeingcreated.

Response:Thankyouforyourcomment.Thedraftingteambelievesthatdefininganewterm“reportingACE”willallow
consistentevaluationofindividualbasperformancetoCPS1andBAAL.Thedraftingteamrealizesthatthisdefinitionofreporting
ACEismoreprescriptive.SinceACEcanvarybetweenBAsaccordingtocontrolalgorithmsthedraftingteamfeltitwasnecessary
todefinereportingACEtoensureuniformity.

MISOStandardsCollaborators

Anentitymustmaintaincompliancewithallstandardsthatareapplicable.Thestandardsarenotintendedtotellanentityhowit
shouldmaintaincompliance.

Organization



YesorNo

Thetechnicallyunjustifiedtightmultipleof"3"epsilon(versusbetween4and5)in
theFrequencyTriggerLimit(FTL)onpage10(Attachment2)oftheStandardviolates
(1)therequirementthatreliabilitystandardsnotinterferewiththe"justand
reasonable"economicbasisformarketefficiencyand(2)therequirementthat
reliabilitystandardsimprovenotreducereliability.Point(2)iscoveredinmy
commentstoQuestion9.Themultipleof3raisesreliabilitycostnotjust
unnecessarily,butperverselyinexchangeforlessreliability.Thatinterfereswiththe
normal"justandreasonable"cost/pricebasisformarketsthatmustallowforcostsof
necessaryreliabilityprovidedthosecostsareallocatedinawaythatisjustand
reasonableandnotperversetoreliability.ItiswellͲknownthat,byBayesian
"multiplication"of"conditional"probability,theprobabilityofbeingattheFTLis
"multipliedby"(not"addedto")the"conditional"probabilityofthesystem'shavinga
onceͲinͲtenͲyearseventprovideditisattheFTL,andisaninfinitesimalfractionofthe
probabilityofthesystem'sreachingaonceͲinͲtenͲyearsevent.Probabilitiesare
fractionsof1.Afractiontimesafractionisaninfinitesimal.Contrarytothe
transmission/congestionengineer'sdeterministicpracticeof"adding"transmission
capacities/contingencies,contingent/conditionalprobabilitiesaremultiplied,not
added.Transmissionmanagement/planningpracticesarenotapplicableto
generation/loadfrequencycontrol.AccordinglytheFTL,regardlessofwhetherthe
multipleofepsilonis3,4or5,isalreadyintherealmoneͲeventͲinhundreds,
thousandsofyears.So,thereisnoissuethatahigher("5")orlower("3")multipleof
epsilonisina"dangerous"zoneofunreliability.Theissueismoreofhow
"unnecessarily"tightthelimitisintermsofaddingtothecostofoperationsthat
participantsthenseektoavoidbyignoringthelimitfortheinitialfiveormore
minutesofaBAALexceedenceandtherebymorethanundothesupposedreliability
benefitofthetightness!

Question10Comment

Consideration of Comments: Project 2010-14.1 BAL-001-1

81

ThedraftingteamconductsamonthlycalltoreviewtheresultsfromtheBAALfieldtrial.Therehavenotbeenanyreliability

Response:Thankyouforyourcomment.Thedraftingteamhasconsideredotheralternativeapproachesandhasselectedthe3
epsilonmodelasthebestandfairestmodelfortherequirement.

KeenResourcesAsiaLtd.

Organization

YesorNo

Question10Comment



Inattachment1,theFA(ActualFrequency)termisdefinedandindicatesaresolutionof
±0.0005Hz.ThisshouldbechangedtoalignwiththeBALͲ005Ͳ0.1bR17thatindicatesa
frequencyresolutionч0.001Hz.



Ideally,allfourofthestandardsundertheBARCSDTwouldbecombinedintoasingle
standardtoreducethelikelihoodofconflictsbetweenthemduringthecompliance
process.Whileseparatingthemmaymakeiteasiertofocusontheminutedetailsof
oneversustheother,thereisalargeriskthattheseparationcancauseconflicts
basedontheinterpretationofoneversustheinterpretationofanother.Asan
exampleofthetypeofconflictthatispossibleascurrentlystructured,onecould
arguethatRequirementR2inBALͲ001supplantRequirementR1inBALͲ002oris
RequirementR1ofBALͲ002thesuperiorrequirement.

Whilenotatrueconflict,itappearsthatthedesignoftheBALͲ001Ͳ1R2relatedto
RBCandtheBALͲ002Ͳ2R1arenotcoordinated.Thedraftingteamshouldreview
thesetworequirementsanddetermineifthereisreasontomodifytheBALͲ002
requirementtomorecloselymatchthedesiretooperatewithinapreͲdetermined
rangebasedonfrequencyunderBALͲ001Ͳ1R2.



No

Consideration of Comments: Project 2010-14.1 BAL-001-1

AssociatedElectric
CooperativeInc,JRO00088

82

Thedraftingteamhasdiscussedcombiningthestandardsintoonebutchosetokeepthemseparate.Thedraftingteambelieves
thatcombiningthetwostandardscouldcreateadditionalconfusion.Inaddition,thedraftingteambelievesthatitwouldbe
difficulttogetindustryagreement.

Response:Thankyouforyourcomment.Thedraftingteamwouldneedfurtherclarificationtobeabletorespondtoyour
commentconcerningaconflict.Thedraftingteamdoesnotseeanythingthatwouldappeartobeconflicting.

XcelEnergy

Response:Thankyouforyourcomment.Thedraftingteamhasremovedtheresolutionfromthedraftstandard.

ManitobaHydro

issuesraisedbyanyRCduringthesecalls.ThedraftingteamencouragesBA’sandRC’stoshareanyspecificoccurrencesthatthey
feelhavereliabilityimpactsasaresultofoperatingunderBAAL.

Organization










SouthCarolinaElectricand
Gas

SERCOCStandardsReview
Group

ArizonaPublicService
Company

IdahoPowerCompany

SPPStandardsReviewGroup


Notawareofanyconflicts.

None.

Nonenoted

No.

No

no

Consideration of Comments: Project 2010-14.1 BAL-001-1






YesorNo

TucsonElectricPower

Organization

Question10Comment

83






Consideration of Comments: Project 2010-14.1 BAL-001-1


84

OnecommenterdisagreedwiththelanguageintheComplianceEnforcementAuthority.Thedraftingteamexplainedthattheyhad
modifiedthelanguagetousestandardNERCapprovedlanguage.

OneortwocommentersfeltthatusingBAALwouldsignificantlyrestrictsmallerBAs.Thedraftingteamstatedthattheywereaware
oftheconcernidentified.However,thedraftingteamisattemptingtodevelopastandardthatwouldbeapplicableto
theentirecontinentanddoesnotknowofanymethodtodistinguishbetweenlargerandsmallerBAs.

Afewcommentersquestionedthefactthatthestandarddidnotcontainanyreportingrequirement.Thedraftingteamexplained
thattheyhadnotincludedanyreportingrequirementsbecausetheybelievedthatthiswasafunctionthatshouldbe
handledbytheRCand/orERO.

Acoupleofcommentersdisagreedwithmodifyingtheterm“Interconnection”.Thedraftingteamexplainedthattheymodifiedthe
definitiontoaddclaritywithregardstothepropernamesoftheInterconnections.Thedraftingteamaskedthe
questioniftheindustryagreedwiththismodification.Only6entitiesdisagreed.Thedraftingteamagreeswiththe
factthatthistermisusedinmanystandardsbutdoesnotbelievethatthemodificationwillhaveanysignificant
impact.

Afewcommentersfeltthattheapplicabilitysectioncontained“requirements”.Thedraftingteamstatedthattheyhadmodifiedthe
applicabilitysectiontoprovideadditionalclarity.

AcoupleofcommentersfeltthatusingBAALcreatedtransmissionissues.Thedraftingteamexplainedthattheyconductamonthly
calltoreviewtheresultsfromtheBAALfieldtrial.TherehavenotbeenanyreliabilityissuesraisedbyanyRCduring
thesecalls.ThedraftingteamencouragesBA’sandRC’stoshareanyspecificoccurrencesthattheyfeelhavereliability
impactsasaresultofoperatingunderBAAL.BAALwasdesignedtoprovideforbettercontrolbyallowingpowerflows
thatdonothaveadetrimentaleffectonreliabilitybutrestrictthosethatdohaveadetrimentaleffectonreliability.

SummaryConsideration:SomecommentersfeltthatsixmonthswasnotenoughtimeinimplementBAAL.Thedraftingteamstated
thattheyhadseenBAsmakemodificationtotheirEMSforthefieldtrialwithin3monthsandthereforebelievesthat
thesixmonthwindowisappropriate.


11.DoyouhaveanyothercommentonBALͲ001Ͳ1,notexpressedinthequestionsabove,fortheBARCSDT?



YesorNo

6)InferringfromSection4.1.3,weinterprettheseSectionstomeanthatthe
“BalancingAuthoritythatprovidesOverlapRegulationServicetoanotherBalancing
Authority”.Inthatcase,arequirementtoholdtheserviceprovidingBAsresponsible
forcalculatingitsCPS1performanceaftercombiningitsReportingACEandFrequency
BiasSettingswiththeReportingACE,andFrequencyBiasSettingsoftheBalancing
AuthorityreceivingtheRegulationService,wouldbenecessary.Sameappliestothe
BAALcalculationimpliedinSection4.1.3

5)Sections4.1.1and4.1.2areunclearastowhichentitiesaresubjecttocomplying
withthestandard.Further,theword“calculates”inbothSectionsturntheseSections
intorequirementsratherthanspecifyingtheentitiesbeingresponsibleformeeting
RequirementsR1andR2.

4)Theapplicableentitiesshouldnotbedefinedbythemethodologytheyusetomeet
thestandard,norshouldrequirementsbeplacedintheApplicableentitydefinition.

3)SimilarlywithACE.ACEisdefinedasSͲA+Bdeltaf.Thescanratedetailsare
subsetsofthatdefinition;theyarenotthedefinition.

2)BAALshouldbeincorporatedwithinarequirementasaperformancelevel.It
shouldnotbeadefinition.

1)Theconceptofadefinitionistoprovideagenericbaselinethatallowsother
descriptiveitemstobeidentified.Forexample:AnInterconnectioncouldbedefined
asacollectionofloads,suppliersandtransmissionthatoperatessynchronously.The
EasternInterconnectionwouldbeunderstoodtobethatgroupof...

Question11Comment

Consideration of Comments: Project 2010-14.1 BAL-001-1

85

3)BasedoncommentsreceivedthedraftingteambelievesthatthedefinitionforreportingACEiscorrectasmodifiedinthedraft

2)Thedraftingteamagreesandhasremoveditfromthestandard.

1)ThedraftingteamisonlycorrectingthedefinitionforInterconnection.Thedraftingteambelievesthatsincetherearefour
InterconnectionsontheNorthAmericanContinentthenthedefinitionsshouldbecorrected.

Response:Thankyouforyourcomment.

ISO'sStandardsReview
Committee

Organization

YesorNo

Question11Comment



3.IsthereamaximumexcludedvalueforoneͲminutesampleperiodsthatwould
invalidateaCPS1orCPS2calculation(i.e.,If59minutesofeveryhourinamonth
wereexcludedbecause50%oftheoneͲminuteperioddatawasinvalid,isthe
CPS1/CPS2valueacceptable?)?Perhapsmodifythe“valid”requirementstobe50%
ofthetimeperiodunderconsiderationorasimilaracceptablevalueforthetime
periodinquestion(oneminute,hour,day,month...).

2.IsNMEconsistentinuseofunitsofmeasure?(ACEismeasureinMWs,butNME
is“themetererrorcorrectionfactor”representingadifferenceinmegawattͲhours).

1.Fortheapplicabilitysection,ERCOT,asthesingleBAfortheentire
interconnection,doesnotprovideorreceiveoverlapregulationservicefromanother
BA.TheSDTshouldconsideraddinganadditionalapplicabilityforthisspecific
situationorreͲformatthesectiontoclarifyapplicabilitytoaBalancingAuthoritynot
involvedinOverlapRegulationService.



86

1.EffectiveDate:TALquestionswhethersixmonthsissufficienttimeforallEMS
vendorstodevelopchangestosoftwareandforallentitiestosuccessfullyimplement

Consideration of Comments: Project 2010-14.1 BAL-001-1

CityofTallahassee

3)The“excludedvalues”calculationhasnotchangedfromwhatisbeingdonetoday.Thecalculationwillbedoneinthesame
mannerasitalwayshasbeencalculated.

2)ThedraftingteamhasmodifiedthecalculationandNMEisnowIME.Inaddition,everythingwithinthecalculationisdonein
MWs.

1)Thedraftingteamhasmodifiedtheapplicabilitysectiontoprovideadditionalclarity.ThedraftingteambelievesthatERCOTis
describedinsection4.1.

Response:Thankyouforyourcomment.

TexasReliabilityEntity

6)Thedraftingteamagreesandhasmadethenecessarymodifications.

4)&5)Thedraftingteamthanksyouforyoursuggestionandhasmodifiedtheapplicabilitysectiontoprovideclarity.

standard.

Organization

YesorNo

3.Attachment2:AretheEpsilon1valuesexpectedtochange?

2.DataRetention:TALsuggestsaclarificationtotherequirementlanguagethatdata
retentionisthelongerofeither(a)thedataretentionperioddefinedinthestandard
or(b)theperiodsincethelastaudit.Astheproposedlanguagereads,theneedto
retainevidencesincethepreviousaudit(iflongerthanthedefinedretentionperiod)
isaddressedinaseparateareafromthedefinedretentionperiod.

thechangeswithintheconfinesoftheCIPstandards,whichwillrequiremultiple
layersoftestingoutsideofscheduledupdates.TALsuggests24months.

Question11Comment



87

1.TheBAALformulaandthecalculatedlimitsaremorerestrictivethancurrent
standards(CPS2andL10)forBalancingAuthoritywithsmallfrequencybiassettings.
ThesmallestfrequencybiassettinginWECCisͲ2MW/0.1Hz.ThelimitationofBAAL
toBAofthissizeissubstantiallyhigh.Forexampleat59.98theBAALLowiscalculated
tobeͲ4.62MWcomparedtoL10limitwhichisͲ7.66.UndertheRBCFieldTrialthe
frequencyerrorsandmanualtimeerrorcorrectionshaveincreased(WECCReport).
Hencethefrequencydeviatesfrom60Hzmoreoftenthaninthepastandthesmaller
BAshavetoexcisemorecontroltostaywithintheirBAAL.TheSDTneedstoaddress
thedisparatetreatmentofsmallBAsundertheproposedBAALrequirementinthe
standard.ThePriorityͲbasedControlengineeringreport(PCEReport)from2005
directedbyNERCstatedthisissue.ThereportsaysthattheproposedBAALmay
requiredisproportionatelymorecontrolfromsmallerBAsthanlargerBAs.Alsoin
Table7underitem7itisstated“PCEhasverifiedthattheproposedBAAL

Consideration of Comments: Project 2010-14.1 BAL-001-1

WesternElectricity
CoordinatingCouncil

3)Thedraftingteamdoesnothaveanyknowledgeofanychanges,butchangesaremadebytheNERCRSandapprovedbythe
NERCOC.

2)Thedraftingteamisusingstandardlanguageforthedataretention.

1)ThedraftingteamhasseenBAsmakemodificationtotheirEMSforthefieldtrialwithin3monthsandthereforebelievesthat
thesixmonthwindowisappropriate.

Response:Thankyouforyourcomment.

Organization

YesorNo

b)TheRBCfieldtrialintheWECCwasimplementedin3distinctphasestotest
theimpactontransmissionpathloading.InitiallytheBAALwaslimitedtono
morethan2timesL10,inphase2theBAALwaslimitedto4timesL10;andin
phase3therewasnocaponBAALat60Hz.DuringPhase3,theReliability
Coordinators(RC)reportedseveralSOLexceedanceassociatedwithhighACE.
TheSOLexceedancesweremitigatedwhenRCsrequestedthehighACEvalue
tobereducedtoL10.TheSDTmustaddresstransmissionloadingissuescaused
byhighACE.

a)DuringthefieldtrialinWECC,anincreaseinUnscheduledFlowwasnoticed
onQualifiedPaths36and66.Inparticular,duringmaintenancewhenthelimit
issignificantlyreducedhighACEvaluesexacerbatepathloading.

2.WECChasthefollowingconcernswithproposedBAALrequirement’simpacton
transmissionpathloadingasaresultoflargeACEvalues:

formulationensuresthatifallBAsarewithintheirBAALatalltimes,the
InterconnectionfrequencywillnotexceedFTL.Therefore,forfrequencytoexceed
FTL,atleastoneBAmustbeoutsideitsBAAL.However,thesefeaturesarenot
uniquetotheselectedBAALformulation;manydifferentsetsofformulationswould
havethesameproperties.Additionalresearchisnecessarytodeterminethe
optimumBAALformulation.Ifscheduledfrequencyisreplacedwith60Hzinthe
proposedBAALformulation,thepropertiesdescribedabovewillnolongerhold
duringperiodsoftimeerrorcorrection.”WECCrecommendstheSDTconsider
developingaformulathatdistributesthecontrolburdenfairlyamongBAs.

Question11Comment

Consideration of Comments: Project 2010-14.1 BAL-001-1

88

2a&b)ThedraftingteamconductsamonthlycalltoreviewtheresultsfromtheBAALfieldtrial.Therehavenotbeenany
reliabilityissuesraisedbyanyRCduringthesecalls.ThedraftingteamencouragesBA’sandRC’stoshareanyspecificoccurrences

1)Thedraftingteamisawareoftheconcernyouhaveidentified.However,thedraftingteamisattemptingtodevelopastandard
thatwouldbeapplicabletotheentirecontinentanddoesnotknowofanymethodtodistinguishbetweenlargerandsmallerBAs.
Inaddition,thedraftingteamhasmodifiedtheequationtonowuseScheduledFrequency.

Response:Thankyouforyourcomment.

Organization

YesorNo

Question11Comment



BALͲ001Ͳ1Attachment1proposestodefineactualfrequencyas“FA(Actual
Frequency)isthemeasuredfrequencyinHz,withminimumresolutionof+/Ͳ0.005
Hz.”Thisproposalincludesanunreasonableresolutionforfrequencymeasurements
andisunnecessary.Accuracyoffrequencydevicesthatareusedinthecalculationof
ACEisalreadyrequiredbyStandardBALͲ005Ͳ1Requirement17.Further,providing
thisproposedrequiredresolutiononsomeexistingindustryequipmentwouldeither
notbepossibleorwouldcausethetotalbandwidthforwhichthefrequencycanbe
monitoredtobereducedtoalevelthatwouldbeunfavorable.Thebasisorrationale
forthisproposedresolutionisnotdiscussedinthebackgrounddocumentand,and
thisrequirementshouldbedeletedfromtheStandard

AbsentCPS2L10limits,atanygiventimeoneBAhasnoincentivetomanageitsACE
andcantakeadvantageoftheregulatingpowerofneighboringBAswhomaybe
balancingmoreeffectively.CPS1remainsinplace,however,thisisarollingoneͲyear
averageanddoesnotprovidethesameincentiveasCPS2.



AECIagreeswithSERCcommentthatAttachment1Interconnectionnamesshould
agreewiththoseinthedraftInterconnectiondefinition.



89

UnderApplicabilitySection4.1.1,theterm“CPS1”isusedbuttheacronymisnot
defineduntilR1.Itshouldbedefinedatthefirstuse.

Consideration of Comments: Project 2010-14.1 BAL-001-1

ManitobaHydro

Response:Thankyouforyourcomment.Thedraftingteamhasmodifiedthedocumentssothattheyareconsistentintheuseof
Interconnectionnames.

AssociatedElectric
CooperativeInc,JRO00088

Thedraftingteamhasremovedtheresolutionyouhavereferenced.

Response:Thankyouforyourcomment.ThefieldtrialexperienceintheEastdoesnotdemonstratethebehavioryouare
describing.Inaddition,RCshavenotreportedanyissuesrelatedtoexcessiveaceduringthemonthlycalls.

ProgressEnergy

thattheyfeelhavereliabilityimpactsasaresultofoperatingunderBAAL. BAALwasdesignedtoprovideforbettercontrolby
allowingpowerflowsthatdonothaveadetrimentaleffectonreliabilitybutrestrictthosethatdohaveadetrimentaleffecton
reliability.

Organization

YesorNo


UndertheEffectiveDateSection,theeffectivedatelanguagehasafewissuesinits
drafting.Itwouldbeclearertousetheword‘following’asopposedtotheword
‘beyond’(andthiswouldalsobemoreconsistentwiththedraftingofsimilarsectionsin
otherstandards).Thewords‘thestandardbecomeseffective’inthethirdlinearenot
needed.Thewords‘madepursuanttothelawsapplicabletosuchEROgovernmental
authorities’maynotbeappropriate.It’snotthelawsapplicabletothegovernmental
authoritiesthatarerelevant,butthelawsapplicabletotheentityitself.Wewould
suggestwordinglike‘orasotherwisemadeeffectivepursuanttothelawsapplicableto
theBalancingAuthority’.Also,EROisnotdefined.

Question11Comment





90

ConcernsabouttransmissionlimitscausedbydroppingCPS2andthelimitationsin
CPS1stillhaven’tbeenaddressed.

Becausethefrequencymodelissimplyusing3timesEpsilon1fortriggerlimits,it
doesnotproduceoptimumresults.The3timesEpsilon1triggerlimitsarenot
calibratedtoaccountforrelaysettingsorfrequencyresponse.The3timesEpsilon1
approachhasa“setitandforgetit”characteristic.Thealternativemodelwould
requireperiodicupdatingasrelaylimitsettingschange,theInterconnection’s
frequencyresponsechanges,andtheperceptionsofthelevelofprotectionneeded
change.Italsodoesnottargetaspecifiedlevelofreliability.

Basedontheexperienceofthepilotprogram,thisproposedstandardwilllikelyallow
gridoperatorstomaintainreliabilitywhilereducingtheneedforregulationreserves
neededtoaccommodateallsourcesofvariabilityonthepowersystem.Asaresult,
theproposedstandardshouldbesupported.

Consideration of Comments: Project 2010-14.1 BAL-001-1

NortheastPowerCoordinating
Council

Response:Thankyouforyourcomment.

AmericanWindEnergy
Association

ThedraftingteamisusingstandardNERCapprovedlanguagefortheeffectivedates.

Response:Thankyouforyourcomment.Thedraftingteamhascorrectedtheerroryouhavedescribed.

Organization

YesorNo

InAttachment2morecompleteguidanceisneededforthetreatmentofamissing
oneminutesamplewhencountingthetimeexpiredduringaBAALlimitviolation.
Whichofthefollowingassumptionsshouldbemadeaboutthemissingsample:
compliance,nonͲcompliance,samestateastheprevioussample,samestateasthe
nextsample,orsimpleomission?

ForCPS1datasubmissions,thenumberofoneminutesamplesinthemonth
becomesanewrequirement.

Question11Comment

DukeEnergy

91

TheComplianceEnforcementAuthoritySectionlanguageisnotthesameasthat

ThereappeartobeincorrectreferencesintheVRF/VSLdocument.Thejustification
forR1referencesBALͲ003Ͳ1forGuideline2insteadofBALͲ001Ͳ1.Thejustificationfor
R2alsoreferencesBALͲ003Ͳ1forGuideline

DukeEnergydoesnotbelievethattheApplicabilitysectionoftheStandardshould
containorclarifyrequirementsofentitiestotheextentpresentedinthedraftBALͲ
001Ͳ1.AsthecurrentdefinitionofOverlapRegulationServicestates“Amethodof
providingregulationserviceinwhichtheBalancingAuthorityprovidingtheregulation
serviceincorporatesanotherBalancingAuthority’sactualinterchange,frequency
response,andschedulesintoprovidingBalancingAuthority’sAGC/ACEequation”,
DukeEnergywouldproposethatApplicabilityshouldbeassignedto“Balancing
AuthoritynotreceivingOverlapRegulationService”.

Consideration of Comments: Project 2010-14.1 BAL-001-1



Theattachmentstatesthatiftheoneminutesampleisbadthenitisexcludedfromthecalculation.

CPS1datasubmissionrequirementshavebeenexpandedtoprovidethenumberofvalidsamplesineachmonth.

ThedraftingteamhasnotseenanyissuesthatduringthefieldtrialthatcanbedirectlyattributabletotheuseofBAAL.BAALwas
designedtoprovideforbettercontrolbyallowingpowerflowsthatdonothaveadetrimentaleffectonreliabilitybutrestrict
thosethatdohaveadetrimentaleffectonreliability.

Response:Thankyouforyourcomment.Thedraftingteamhasexploredthealternativemodelthatisdescribedandhaschosen
togowiththe3Epsilonmodel.

Organization

YesorNo
specifiedintheBackgroundInformationforQualityReviewsdatedFebruary2012.

Question11Comment



Thefrequencyresolutionappearstootight0.0005Hz(comparedto0.001inBALͲ005)
andthenewterm,NetMeteringErrorisprescriptiveonhowmeteringerroris
corrected.

oThereportingACEtermthattheteamcreatedseemsunnecessaryasACEisalready
defined.ItalsoexpandsontheexpectationsofACE.

oThedraftingteamchangedtheNERCdefinitionofInterconnections.Thistermis
usedinmanystandardsandmayhaveimpactonthem.

GeneralCommentsandObservations



92

LG&EandKUServicessuggeststhattheSDTclarifiesthatthestandardwillnot
requiremonthlyreportingasifcurrentlyperformedbytheBA(CPS1andBAAL)to
SERC/NERC/FERCbutthattheBAwillneedtoevaluateCPS1monthlyandBAAL

Consideration of Comments: Project 2010-14.1 BAL-001-1

LG&EandKUServices

TheNetMeteringError(NME)haschangedtoInterchangeMetererror(IME).Basedonindustrycommentsreceived,thedrafting
teamhaselectedtonotmakeanymodificationstotheterm.

Thedraftingteamhasremovedtheresolutionfromtheattachment.

ThedraftingteamrealizesthatthisdefinitionofreportingACEismoreprescriptive.SinceACEcanvarybetweenBAsaccordingto
controlalgorithmsthedraftingteamfeltitwasnecessarytodefinereportingACEtoensureuniformity.

Response:Thankyouforyourcomment.Thedraftingteammodifiedthedefinitiontoaddclaritywithregardstotheproper
namesoftheInterconnections.Thedraftingteamaskedthequestioniftheindustryagreedwiththismodification.Only6entities
disagreed.Thedraftingteamagreeswiththefactthatthistermisusedinmanystandardsbutdoesnotbelievethatthe
modificationwillhaveanysignificantimpact.

MRONSRF

ThedraftingteamhasmodifiedtheComplianceEnforcementAuthoritytousestandardNERCapprovedlanguage.

Thankyouforcatchingthiserror.Thedraftingteamhascorrectedthereference.

Response:Thankyouforyourcomment.Thedraftingteamhasmodifiedtheapplicabilitysectiontoprovideadditionalclarity.

Organization

YesorNo
continuously.

Question11Comment





PleasenoteandreadtheWECCPWGreportonRBC.Thankstothedraftingteamfor
theirefforts.

MISOsupportsthisstandardgenerallyand,inparticular,theconceptanduseofBAAL
inlieuofCPS2.



a.RFCseeksfurtherclaritysurroundingtheapplicabilityofBalancingAuthorities
whichdonotprovideRegulatingService.IfaBalancingAuthoritydoesnotprovide
RegulatingService,aretheysubsequentlynotsubjecttotherequirementsinthe
standard?Iftheyarenotsubjecttotherequirementsinthestandard,RFC
recommendsremovingsection4.1.3sinceitisnotneededaswell.

1.Applicabilitysection

ReliabilityFirstoffersthefollowingcommentforconsideration:



93

Sections4.1.1and4.1.2areunclearastowhichentitiesaresubjecttocomplyingwith
thestandard.Further,theword“calculates”inbothSectionsturntheseSectionsinto
requirementsratherthanspecifyingtheentitiesbeingresponsibleformeeting

Consideration of Comments: Project 2010-14.1 BAL-001-1

IndependentElectricity
SystemOperator

Thedraftingteamhasmodifiedtheapplicabilitytoprovideadditionalclarity.

Response:Thankyouforyourcomment.AllBAsaresubjecttothisstandardwiththeexceptionofthoseBAsreceivingOverlap
RegulationService.

ReliabilityFirst

Response:Thankyouforyourcomment.Thedraftingteamplansonreadingthereportonceitispublished.

TucsonElectricPower

Response:Thankyouforyourcomment.

MISOStandardsCollaborators

Response:Thankyouforyourcomment.Thedraftingteamhasnotincludedanyreportingactivitywithinthestandard.The
draftingteambelievesthatreportingwillbedeterminedbytheRCandERO.

Organization

YesorNo

RequirementsR1andR2.InferringfromSection4.1.3,weinterprettheseSectionsto
meanthatthe“BalancingAuthoritythatprovidesOverlapRegulationServiceto
anotherBalancingAuthority”.Inthatcase,arequirementtoholdtheservice
providingBAsresponsibleforcalculatingitsCPS1performanceaftercombiningits
ReportingACEandFrequencyBiasSettingswiththeReportingACE,andFrequency
BiasSettingsoftheBalancingAuthorityreceivingtheRegulationService,wouldbe
necessary.SameappliestotheBAALcalculationimpliedinSection4.1.3.

Question11Comment



OnAttachment1,theInterconnectionnamesneedtoberevisedtoagreewiththe
Interconnectionasstatedearlierinquestion2.

ShouldthestandardincludereportingrequirementstotheRRO?



SouthCarolinaElectricandGassupportsthecommentssubmittedbytheSERCOC
StandardsReviewGroup.



TheApplicabilitysectionofthestandardtakesanunusualformat.4.1.1and4.1.2
seemmoreappropriateassubrequirementsforR1andR2,respectively,thanas
applicabilitystatements.IftheapplicabilitysectionincludesBalancingAuthoritiesand
BalancingAuthoritiesProvidingOverlapRegulationService,then4.1.1and4.1.2
shouldmovetothesubͲrequirementssection.

Consideration of Comments: Project 2010-14.1 BAL-001-1

94

Response:Thankyouforyourcomment.ThedraftingteamhasmodifiedtheapplicabilitytonolongerreferenceBAsproviding

ConstellationEnergyControl
andDispatch,LLC

Response:Thankyouforyourcomment.PleaserefertoourresponsetothecommentssubmittedbytheSERCOCStandards
ReviewGroup.

SouthCarolinaElectricand
Gas

Thedraftingteamthanksyouforcatchingthiserrorandtheyhavemadethenecessarymodifications.

Response:Thankyouforyourcomment.Thedraftingteamhasnotincludedanyreportingactivitywithinthestandard.The
draftingteambelievesthatreportingwillbedeterminedbytheRCandERO.

SERCOCStandardsReview
Group

Response:Thedraftingteamthanksyouforyourcommentandhasmodifiedtheapplicabilitysectiontoprovideclarity.

Organization



YesorNo

CurrentlySPPisworkingonaprojecttoconsolidateBAswithintheregionintoa
singleBA.TheproposedcompletiondateisscheduledforMarch1,2014.Ifthe
standardweretobecomeeffectivepriortothisdate,considerableexpenseandeffort
wouldbeexpendedneedlesslyoncetheconsolidationtakesplace.CouldSPPrequest
aregionalvarianceforexemptionfromR2untilMarch1,2014?

Currently,theBAsthatareparticipatingintheBAALfieldtrialareexemptfromCPS2
compliance.DuringthetransitionfromBALͲ001Ͳ0.1atoBALͲ001Ͳ1,thereneedtobe
exemptionsextendedduringtestingofBAALcontrolschemes.

Theeffectivedateasproposedinthedraftstandardissix(6)monthsfollowing
approvalbyapplicableregulatoryauthorities.Thisistooshort.Wewouldsuggesta
12Ͳmonthwindowbeforetheapprovedstandardbecomeseffective.Thisprovides
theBAwithtimetoconsultwithEMSvendors,designandretrofitnecessarychanges
toexistingcontrolalgorithmsandtestingͲbothacceptancetestingfortheAGC
changesandparalleltestingalongsideexistingAGCsystemstoensuresatisfactory
operation.

Question11Comment



95

Inthefirstparagraphinthebackgroundandrationalesectiononpage4ofthe

Theimplementationplanstatesthatsixmonthsarerequiredtomakesoftware
changestoanEMStoaccommodatethechangetothestandard.Isthisbasedonthe
actualexperienceofthoseparticipatinginthefieldtrial?Ifnot,thedraftingteam
shouldreachouttothefieldtrialparticipantstofindouthowlongittookthemto
implementthechanges.Ifitis,thedocumentationshouldstatethisclearly.

Consideration of Comments: Project 2010-14.1 BAL-001-1

ACESPowerMarketing
StandardsCollaborators

Avariancecanberequestedbyanyoneatanytime.

Theexemptionwouldstayineffectuntilthenewstandardgoesintoeffect.

Response:Thankyouforyourcomment.ThedraftingteamhasseenBAsmakemodificationtotheirEMSforthefieldtrialwithin
3monthsandthereforebelievesthatthesixmonthwindowisappropriate.

SPPStandardsReviewGroup

OverlapRegulationService.

Organization

YesorNo

TheminimumresolutionforactualfrequencyinAttachment2shouldberemoved.
First,itisessentiallyarequirementandrequirementscannotbewritteninto
attachments.Second,itraisesthebaroverthefrequencymeasurementaccuracy
establishedinBALͲ005Ͳ0.1bR17withoutjustification.

Totheextentthataresponsibleentityissubjecttoperiodicreportingthatwill
demonstratecompliance,wequestiontheneedforadataretentionperiodofone
fullyear.NomorethanthreemonthsofBAALdatashouldberequiredWedisagree
withrequiringdatatoberetainedforuptofouryears.First,thecurrentstandard
onlyrequiredtheBAtoretainthedataforoneyear.Nojustificationhasbeen
providedforraisingthebar.Second,NERCreceivesperiodicreportsforCPS1and
currentlyfortheBAALlimits.Thus,theycanretainthesereportsiftheyneedthem.
OneyearissufficienttimeforNERCtoraiseanyissuesorquestionsabouttheinput
datausedinthecalculationforCPS1andtheBAALlimits.Ifnoissueshavearisento
causeNERCtorequestdataretentionforalongerperiodwithinthefirstyear,then
theresponsibleentityshouldnotberequiredtoretainit.Third,retentionofdata
beyondthethreeyearBAauditcycleisnotconsistentwithNERCRulesofProcedure.
Section3.1.4.2ofAppendix4CͲComplianceMonitoringandEnforcementProgram
statesthatthecomplianceauditwillcovertheperiodfromthedayafterthelast
complianceaudittotheenddateofthecurrentcomplianceaudit.

ACEneedstobecapitalizedinthesecondparagraphoftheDataRetentionsection.

WethinkthenewvariationonthemetererrortermintheACEequationisactually
moreconfusingthanthepreviousmetererrorterm.Theprevioustermwasclear
thathourlyintegrationoftheinstantaneousmetervalueswasbeingcomparedtothe
revenuequalitymeters.Thenewtermdoesnotstatethisasclearly.

backgrounddocument,“CompliancePerformanceStandard”shouldbe“Control
PerformanceStandard”.

Question11Comment

Consideration of Comments: Project 2010-14.1 BAL-001-1

96

Response:Thankyouforyourcomment.ThedraftingteamhasseenBAsmakemodificationtotheirEMSforthefieldtrialwithin
3monthsandthereforebelievesthatthesixmonthwindowisappropriate

Organization

YesorNo

Question11Comment



TheproposedBAALmeasureinreplacementofthecurrentCPS2removesa
performancemeasurethatisindependentoftherestoftheinterconnection
performance.ThecurrentCPS2isbasedoninterconnectionstatisticalperformance
andprovidesanentitywithameasurethatisanindicationofhowwellanentityis
balancedwithenergyresourcestoloadobligations.TheproposedBAALmeasureis
verycloseinconcepttothemeasureforthecurrentCPS1andhasasimilareffect.As
theinterconnectionfrequencymovesawayfrom60HztheBAALboundariesshrink
andcanshrinktolevelsthatarelowerthanmeteringaccuraciesinherentincontrol
systemsandthenormalvariationsofACEthatcanoccur.ThecurrentCPS1tiesan
entitiescontrolperformancetorestoftheinterconnectionasitisafunctionofactual
systemfrequency.ThecurrentCPS2reflectsanentitiesindependentperformance
formaintaininganacceptablebalanceofloadtoenergyresources.Itisimportantfor
anentitytohavesomemeasureofitsownperformanceapartfromtheperformance
oftheinterconnection.Theremaybeareliabilityneedto"tighten"theperformance
metricsaroundwhatconstitutesgoodandacceptable"balance"ofloadobligations
andenergyresources,butitisimportanttomaintainametricthatreflectsanentities
performanceapartfromtherestoftheinterconnection.

Consideration of Comments: Project 2010-14.1 BAL-001-1

97

Response:Thankyouforyourcomment.ThedraftingteamagreesthatCPS2isanindependentmeasureofaBAsperformance.Itis

KCP&L

Thedraftingteamhasremovedtheresolutionfromtheattachment.

Thedraftingteambelievesthatdatashouldberetainedasdefinedinthecurrentstandard.Thisisthesameasrequiredbymany
otherstandardsineffect.AquicksearchoftheRulesofProcedure(ROP)didnotfindanythingthatwouldimplythatthis
recommendeddataretentionperiodisconflictingwiththeROP.

Thedraftingteamthanksyouforfindingthiserror.Thedraftingteamhasmadethenecessarymodificationstocorrectthis
oversight.

TheNetMeteringError(NME)haschangedtoInterchangeMetererror(IME).Basedonindustrycommentsreceived,thedrafting
teamhaselectedtonotmakeanymodificationstotheterm.

Thedraftingteamthanksyouforfindingthiserror.Thedraftingteamhasmadethenecessarymodificationstocorrectthis
oversight.

Organization

YesorNo

Question11Comment



98

Therecentincreaseinintermittentresources,suchaswindandsolargeneration,has
increasedbalancingchallengesduetovariabilityingeneration,drivingactual
generationtodifferfromscheduledgeneration.ByeliminatingCPS2andreplacingit
withtherelaxedBAALlimit,theproposedperformancestandarddoesnotaddress
thepotentialforasingleBAtoleanonthegridwithdeliberateunscheduledenergy
flowsorinadvertentenergy,takinganyaccumulatedbenefitsforitselfandpossibly
evenjeopardizingreliabilityand/orharmingotherentitiesonthegrid.The
detrimentalimpactsofdeliberateinadvertentflowstoloadcustomersand
transmissioncustomersonthegridcouldbesubstantial.Pricesignalsgenerallydrive
correlatedbehavioracrossmultiplemarketparticipants.Loadcustomerscouldhave
serviceinterruptedifmultipleBAs,followingmarketpricesignals,alldecidedto
inaccuratelyscheduletheirexpectedhourlyaveragegenerationinthesamedirection
inthesamehour,withoutsufficientprospectiveabilitytorestoreandsustain
“balance”withintheBAA,ifneeded.Transmissioncustomersarelikelytobe
frequentlyinterruptedduetounscheduledflows,ifoneormoreBAstakeadvantage
oftheBAALlimitanddeliberatelyrelyoninadvertentenergytomeettheirexpected
BAAimbalances,asBAAimbalancescanundisputedlyoccurwithoutknowledgeor
regardtotransmissionavailabilityorcoordination.Inorder890,FERCmadeitclear
thatitwasinappropriateforgeneratorswithinaBAAto“dumppoweronthesystem
orleanonothergeneration...ThetieredimbalancepenaltiesadoptedintheFinal
Rulegenerallyprovideasufficientincentivenottoengageissuchbehavior”.The
Commissionunambiguouslywantedtoencourageaccurateschedulingofa
generator’soutputwithinaBAA.Thoughatthetimeofthe890rulingthe
CommissionchosenottoimposesimilarrulespreventingBAsthemselvesandtheir
affiliategeneratorsfromleaningonthegrid,theyrecognizedthattherewasa
potentialforsuchbehavior,andnotedthatitcouldtakeactionunderFPAsection215
ifsuchdeliberateinadvertentflowsweredegradingreliabilityorharmingother

Consideration of Comments: Project 2010-14.1 BAL-001-1

PowerexCorp.

notafunctiononInterconnectionFrequencyandcanresultinindividualBAcontrolthatdoesnotsupportinterconnectionfrequency.
BAALwasdesignedtoprovideforbettercontrolbyallowingpowerflowsthatdonothaveadetrimentaleffectonreliabilitybut
restrictthosethatdohaveadetrimentaleffectonreliability.

Organization

YesorNo

Question11Comment

99

2.MinimumBAbalancingreserverequirements,setprospectively,toensurethatthe
amountofbalancingreservescarriedonthebroadergridaresufficienttomaintain
gridreliability.Relianceonperformancestandards,asalaggingindicator,maybe
insufficienttoensurereliabilityonaprospectivebasis,particularlyassuch
performancestandardsbecomemoreliberalsuchaswiththeproposedBAALlimits.
InOrder693,FERCnotedthatwhilethecontrolperformancestandardmetriclike
Requirement2,isusefulinidentifyingtrendsrelatingtopoorregulatingpractices,
specificationofminimumreserverequirementstobemaintainedatalltimeswould

1.EnforceablerulesandprocessesthatensurethatBAAimbalancescanbe
immediatelylimitedifapplicabletransmissionflowgatelimitsarereached.
UnscheduledenergyflowsresultingfromBAAimbalancesshouldclearlyhavethe
lowestpriorityaccesstotransmission,behindallcustomerswhohaveinvested,and
appropriatelyscheduled,tousethetransmissionnetwork.

customers.Theseissueshavebroughttotheforefronttheimportanceofthepublic
releaseofBAAͲspecifichourlyinadvertentflowdata.Theinadvertentflowsresulting
fromtheoperationsofoneBAAcanhaveasignificantimpactonitsneighboringBAAs
andthetransmissioncustomersonthegrid.Powerexfeelsitpublicreleaseofthe
hourlyinadvertentflowdatawouldgiveallentitiesabetterunderstandingoftheway
theBAAsareoperatingintheirregionandfacilitatecoordinatedoperationstoensure
theadverseimpactsofinadvertentflowscanbeappropriatelyminimized.The
broaderwholesaleelectricitygridmaybeavaluablebalancingresourceforboth
reducingthewearandtearondispatchablegenerationresources.However,itis
imperativetoreliability,openaccesstransmissionprinciples,andproperfunctioning
wholesaleenergymarkets,thatincreasedutilizationoftheelectricitygrid’sinherent
transmissionflexibilityandinherentfrequencyflexibilitybeachievedwithinan
appropriateframework.Morespecifically,beforeimplementingtheBAALlimitsin
BALͲ001andallowingBAstousethebroaderelectricitygriddeliberatelyasa
balancingresource,byeitherreducingtheamountofbalancingreservesdispatched,
and/orpotentiallyreducingtheamountofbalancingreservescarried,thefollowing
mayberequired:

Consideration of Comments: Project 2010-14.1 BAL-001-1

Organization

YesorNo

4.HourlyBAAimbalancedataismadepublic(afterͲtheͲfact,inasimilarmannerto
thewayscheduledtransmissionusageisreleasedonOASIS),sothatNERC,the
RegionalEntities,BAs,impactedtransmissioncustomers,etc,canusethedatato
monitortheinappropriateuseofunscheduledflow.UnlessBALͲ001(orthe
frameworkmadeupbytheBARCstandards)includesrequirementsforperformance
inamannerthatpreventsanentityfromdeliberatelyleaningonthegridtogain
commercialadvantage,itwouldbeinappropriatetoadoptthestandardinitspresent
form.

3.Thebenefitsofutilizingtheflexibilityinthegridareappropriatelyallocatedtoall
gridparticipants,througheitherBAAconsolidationorBAAcoordinationframeworks,
andFERCcostallocationoversight.IndividualBAAsshouldnotbeabletoleanonthe
griddisproportionally,hopingthattherearesufficientBAswithamoreconservative
approachtoGoodUtilityPracticetomaintainthegrid’sreliability,attheircustomers’
inequitableexpense.

complementthecontrolperformancestandardmetricsbyprovidingrealͲtime
requirementsnecessaryforpropercontrol.FERCdirectedtheEROtodevelopa
processtocalculatetheminimumregulatingreserveforaBA,takingintoaccount
expectedloadandgenerationvariationandtransactionsbeingrampedintooroutof
theBA.

Question11Comment

Consideration of Comments: Project 2010-14.1 BAL-001-1

10
0

3&4)TherehavenotbeenanyreliabilityissuesraisedbyanyRCduringthesecalls.ThedraftingteamencouragesBA’sandRC’s
toshareanyspecificoccurrencesthattheyfeelhavereliabilityimpactsasaresultofoperatingunderBAAL. BAALwasdesignedto
provideforbettercontrolbyallowingpowerflowsthatdonothaveadetrimentaleffectonreliabilitybutrestrictthosethatdo

2)ThedraftingteambelievesthatyourreferencetoaminimumregulatingreserverequirementfromFERCOrder693iscontained
inPhase2ofProject2010Ͳ14.

1)ThedraftingteambelievesthatthisisoutsidethescopeoftheindustryapprovedSARandthattransmissionpriorityisaNAESB
concern.ThedraftingteamrecommendsthatyousubmitaSARifyoufeelthatthisshouldbepursuedfurther.

Response:Thankyouforyourcomment.

Organization

YesorNo



x
x
x
x
x

FrequencyError
ManualTimeErrorCorrections
Transmissionissues
Unscheduledflowevents
SmallBAsInthefieldtrial,thereisdirectiononwhentheRCshouldintervene
duringfrequencydeviationsbelowtheFTL.BPAbelievesthisshouldberetained
eitherinformallyorformallyinthestandard.

PleaserefertotheWECCReliabilityͲbasedControlFieldTrialFinalReportJuly2012
PerformanceWorkGroupDraftdocument.

ThesubͲrequirementsof4.1oftheapplicabilitysectioncontaininstructions.BPA
suggeststhatonly4.1and4.1.3(anew4.2created)beusedinsteadandtherest
eliminatedandaddedasarequirement.

Question11Comment



10
1

Thereneedstobeanunderstandingandappreciationoftheincreasingnumberof
newlyͲregisteredmarketparticipantGeneratorOperatorsthatarenotfromthe
traditional,verticallyintegratedutilityenvironment,andtheirimpactonaBalancing
Authority’sabilitytobalance.WeencouragetheSDTtothinkofopportunitiesto
developappropriaterequirementsinordertoensurethatGeneratorOperatorscan
helpsupporttheobjectivesofbalancingloadandgenerationinareliablemanner.The
backgroundinformationonbalancingsometimesrefersbacktotheformer“NERC
Policy”,atatimewhenthepreceding“ControlArea”modelapplicabilityhad
differentoperatingcharacteristicsthantoday’smoregranularfunctionalmodelentity
intermsofBalancingAuthority,GeneratorOperator,LoadServingEntity(Demand

Consideration of Comments: Project 2010-14.1 BAL-001-1

AmericanElectricPower

Thedraftingteamplanstoreviewthepaperyoureferencedoncethedocumenthasbeenpublished.

Response:Thankyouforyourcomment.Thedraftingteamhasmodifiedtheapplicabilitysectiontoaddressyourcommentand
othercommentsfromtheindustry.

BonnevillePower
Administration

haveadetrimentaleffectonreliability.

Organization

YesorNo

SideLoadManagement),MarketOperator,etc.Thestatedcomplianceapplicability
withintheproposedStandardfailstoaddressinherentimpactoftheseother
functionalentitiesandvariablesonaBalancingAuthority’ssoleabilitytocomplywith
theserequirementsintoday’sactualpractice.BalancingAuthoritiesthatarepartof
regionalenergyand/orancillaryservicemarketsmayhaveuniquechallengeswith
respecttodeploymentofBalancingAuthorityresources.Forexample,thefailureof
followingmarketdeploymentmayonlyinvolveafinancialmarketcharge,however
theresultscouldhavesignificantimpactonBalancingAuthorityobligations.

Question11Comment




NVEnergy

IdahoPowerCompany

None

No.

Nocomments

Consideration of Comments: Project 2010-14.1 BAL-001-1



ENDOFREPORT



ArizonaPublicService
Company

10
2

Response:Thankyouforyourcomment.FERChasstatedthatitistheultimateresponsibilityoftheBAtoensurebalanceofload
andgenerationinareliablemanner.

Organization

StandardBALͲ001Ͳ2–RealPowerBalancingControlPerformance

StandardDevelopmentRoadmap
Thissectionismaintainedbythedraftingteamduringthedevelopmentofthestandardandwill
beremovedwhenthestandardbecomeseffective.
DevelopmentStepsCompleted:
1. TheSARforProject2007Ͳ18,ReliabilityBasedControls,waspostedfora30Ͳdayformal
commentperiodonMay15,2007.
2. ArevisedSARforProject2007Ͳ05,ReliabilityBasedControls,waspostedforasecond
30ͲdayformalcommentperiodonSeptember10,2007.
3. TheStandardsCommitteeapprovedProject2007Ͳ18,ReliabilityBasedControls,tobe
movedtostandarddraftingonDecember11,2007.
4. TheSARforProject2007Ͳ05,BalancingAuthorityControls,waspostedfora30Ͳday
formalcommentperiodonJuly3,2007.
5. TheStandardsCommitteeapprovedProject2007Ͳ05,BalancingAuthorityControls,to
bemovedtostandarddraftingonJanuary18,2008.
6. TheStandardsCommitteeapprovedthemergerofProject2007Ͳ05,BalancingAuthority
Controls,andProject2007Ͳ18,ReliabilityͲbasedControls,asProject2010Ͳ14,Balancing
AuthorityReliabilityͲbasedControls,onJuly28,2010.
7. TheNERCStandardsCommitteeapprovedbreakingProject2010Ͳ14,Balancing
AuthorityReliabilityͲbasedControls,intotwophases;andmovingPhase1(Project2010Ͳ
14.1,BalancingAuthorityReliabilityͲbasedControls–Reserves)intoformalstandards
developmentonJuly13,2011.
8. Thedraftstandardwaspostedfor30ͲdayformalindustrycommentperiodfromJune4,
2012throughJuly3,2012.
ProposedActionPlanandDescriptionofCurrentDraft:
Thisisthesecondpostingoftheproposednewstandard.Thisproposeddraftstandardwillbe
postedfora45ͲdayformalcommentperiodbeginningonMarch12,2013throughApril25,
2013.

FutureDevelopmentPlan:
AnticipatedActions
1. Secondposting

AnticipatedDate
March/April2013

2. InitialBallot

April2013

3. RecirculationBallot

October2013

4. NERCBOTadoption.

November2013

BALͲ001Ͳ2
January1,2013



Page1of13



StandardBALͲ001Ͳ2–RealPowerBalancingControlPerformance

DefinitionsofTermsUsedinStandard
Thissectionincludesallnewlydefinedorrevisedtermsusedintheproposedstandard.Terms
alreadydefinedintheReliabilityStandardsGlossaryofTermsarenotrepeatedhere.Newor
reviseddefinitionslistedbelowbecomeapprovedwhentheproposedstandardisapproved.
Whenthestandardbecomeseffective,thesedefinedtermswillberemovedfromtheindividual
standardandaddedtotheGlossary.
RegulationReserveSharingGroup:AgroupwhosemembersconsistoftwoormoreBalancing
Authoritiesthatcollectivelymaintain,allocate,andsupplytheregulatingreserverequiredfor
allmemberBalancingAuthoritiestouseinmeetingapplicableregulatingstandards.
RegulationReserveSharingGroupReportingACE:Atanygiventimeofmeasurementforthe
applicableRegulationReserveSharingGroup,thealgebraicsumoftheReportingACEs(as
calculatedatsuchtimeofmeasurement)oftheBalancingAuthoritiesparticipatinginthe
RegulationReserveSharingGroupatthetimeofmeasurement.
ReportingACE:ThescanratevaluesofaBalancingAuthority’sAreaControlError(ACE)
measuredinMW,whichincludesthedifferencebetweentheBalancingAuthority’snetactual
InterchangeanditsscheduledInterchange,plusitsFrequencyBiasobligation,plusanyknown
metererrorplusAutomaticTimeErrorCorrection(ATEC–IfoperatingintheWestern
InterconnectionandintheATECmode).
ReportingACEiscalculatedasfollows:



ReportingACE=(NIAоNIS)о10B(FAоFS)оIME+IATEC


Where:
NIA(ActualNetInterchange)isthealgebraicsumofactualmegawatttransfersacrossall
TieLinesandincludesPseudoͲTies.BalancingAuthoritiesdirectlyconnectedvia
asynchronoustiestoanotherInterconnectionmayincludeorexcludemegawatt
transfersonthosetielinesintheiractualinterchange,providedtheyareimplemented
inthesamemannerforNetInterchangeSchedule.
NIS(ScheduledNetInterchange)isthealgebraicsumofallscheduledmegawatt
transfers,includingDynamicSchedules,withadjacentBalancingAuthorities,andtaking
intoaccounttheeffectsofscheduleramps.BalancingAuthoritiesdirectlyconnectedvia
asynchronoustiestoanotherInterconnectionmayincludeorexcludemegawatt
transfersonthosetielinesintheirscheduledInterchange,providedtheyare
implementedinthesamemannerforNetInterchangeActual.
B(FrequencyBiasSetting)istheFrequencyBiasSetting(innegativeMW/0.1Hz)forthe
BalancingAuthority.
10istheconstantfactorthatconvertsthefrequencybiassettingunitstoMW/Hz.
BALͲ001Ͳ2
January1,2013



Page2of13



StandardBALͲ001Ͳ2–RealPowerBalancingControlPerformance
FA(ActualFrequency)isthemeasuredfrequencyinHz.
FS(ScheduledFrequency)is60.0Hz,exceptduringatimecorrection.
IME(InterchangeMeterError)isthemetererrorcorrectionfactorandrepresentsthe
differencebetweentheintegratedhourlyaverageofthenetinterchangeactual(NIA)
andthecumulativehourlynetInterchangeenergymeasurement(inmegawattͲhours).
IATEC(AutomaticTimeErrorCorrection)istheadditionofacomponenttotheACE
equationthatmodifiesthecontrolpointforthepurposeofcontinuouslypayingback
PrimaryInadvertentInterchangetocorrectaccumulatedtimeerror.AutomaticTime
ErrorCorrectionisonlyapplicableintheWesterninterconnection.
on/off peak

IATEC

PII

accum

1  Y * H

whenoperatinginAutomaticTimeErrorCorrectioncontrolmode.

IATECshallbezerowhenoperatinginanyotherAGCmode.
x

Y=B/BS.

x

H=NumberofHoursusedtopaybackPrimaryInadvertentInterchangeenergy.The
valueofHissetto3.

x

BS=FrequencyBiasfortheInterconnection(MW/0.1Hz).

x

PrimaryInadvertentInterchange(PIIhourly)is(1ͲY)*(IIactualͲB*ȴTE/6)

x

IIactualisthehourlyInadvertentInterchangeforthelasthour.

x

ȴTEisthehourlychangeinsystemTimeErrorasdistributedbytheInterconnection
TimeMonitor.Where:



ȴTE=TEendhour–TEbeginhour–TDadj–(t)*(TEoffset)

x

TDadjistheReliabilityCoordinatoradjustmentfordifferenceswithInterconnection
TimeMonitorcontrolcenterclocks.

x

tisthenumberofminutesofManualTimeErrorCorrectionthatoccurredduringthe
hour.

x

TEoffsetis0.000or+0.020orͲ0.020.

x

PIIaccumistheBalancingAuthority’saccumulatedPIIhourlyinMWh.AnOnͲPeakand
OffͲPeakaccumulationaccountingisrequired.
Where:

PII

on/off peak
accum

=lastperiod’s

on/off peak

PII

accum

+PIIhourly


AllNERCInterconnectionswithmultipleBalancingAuthoritiesoperateusingtheprinciples
ofTieͲlineBias(TLB)ControlandrequiretheuseofanACEequationsimilartothe
ReportingACEdefinedabove.Anymodification(s)tothisspecifiedReportingACE
BALͲ001Ͳ2
January1,2013



Page3of13



StandardBALͲ001Ͳ2–RealPowerBalancingControlPerformance
equationthatis(are)implementedforallBAsonaninterconnectionandis(are)consistent
withthefollowingfourprincipleswillprovideavalidalternativeReportingACEequation
consistentwiththemeasuresincludedinthisstandard.
1. Allportionsoftheinterconnectionareincludedinoneareaoranothersothat
thesumofallareageneration,loadsandlossesisthesameastotalsystem
generation,loadandlosses.
2. Thealgebraicsumofallareanetinterchangeschedulesandallnetinterchange
actualvaluesisequaltozeroatalltimes.
3. TheuseofacommonscheduledfrequencyFSforallareasatalltimes.
4. Theabsenceofmeteringorcomputationalerrors.(Theinclusionanduseofthe
IMEtermtoaccountforknownmeteringorcomputationalerrors.)

Interconnection:Whencapitalized,anyoneofthefourmajorelectricsystemnetworksinNorth
America:Eastern,Western,ERCOTandQuebec.

BALͲ001Ͳ2
January1,2013



Page4of13



StandardBALͲ001Ͳ2–RealPowerBalancingControlPerformance
A. Introduction
1.

Title:

RealPowerBalancingControlPerformance

2.

Number:

BALͲ001Ͳ2

3.

Purpose:

TocontrolInterconnectionfrequencywithindefinedlimits.

4.

Applicability:
4.1. BalancingAuthority
4.1.1 ABalancingAuthorityreceivingOverlapRegulationServiceisnotsubject
toControlPerformanceStandard1(CPS1)orBalancingAuthorityACE
Limit(BAAL)complianceevaluation.
4.1.2 ABalancingAuthoritythatisamemberofaRegulationReserveSharing
GroupistheResponsibleEntityonlyinperiodduringwhichtheBalancing
Authorityisnotinactivestatusundertheapplicableagreementor
governingrulesfortheRegulationReserveSharingGroup.
4.2. RegulationReserveSharingGroup

5.

(Proposed)EffectiveDate:
5.1.



Firstdayofthefirstcalendarquarterthatissixmonthsbeyondthedatethat
thisstandardisapprovedbyapplicableregulatoryauthorities,orinthose
jurisdictionswhereregulatoryapprovalisnotrequired,thestandardbecomes
effectivethefirstdayofthefirstcalendarquarterthatissixmonthsbeyondthe
datethisstandardisapprovedbytheNERCBoardofTrustees’,orasotherwise
madepursuanttothelawsapplicabletosuchEROgovernmentalauthorities.



B. Requirements
R1.

TheResponsibleEntityshalloperatesuchthattheControlPerformanceStandard1
(CPS1),calculatedinaccordancewithAttachment1,isgreaterthanorequalto100
percentfortheapplicableInterconnectioninwhichitoperatesforeach12Ͳmonth
period,evaluatedmonthly.[ViolationRiskFactor:Medium][TimeHorizon:RealͲtime
Operations]

R2.

EachBalancingAuthorityshalloperatesuchthatitsclockͲminuteaverageofReporting
ACEdoesnotexceeditsclockͲminuteBalancingAuthorityACELimit(BAAL)formore
than30consecutiveclockͲminutes,ascalculatedinAttachment2,fortheapplicable
InterconnectioninwhichtheBalancingAuthorityoperates.[ViolationRiskFactor:
Medium][TimeHorizon:RealͲtimeOperations]

C. Measures
M1. TheResponsibleEntityshallprovideevidence,uponrequest,suchasdatedcalculation
outputfromspreadsheets,EnergyManagementSystemlogs,softwareprograms,or
otherevidence(eitherinhardcopyorelectronicformat)todemonstratecompliance
withRequirementR1.
BALͲ001Ͳ2
January1,2013



Page5of13



StandardBALͲ001Ͳ2–RealPowerBalancingControlPerformance
M2. EachBalancingAuthorityshallprovideevidence,uponrequest,suchasdated
calculationoutputfromspreadsheets,EnergyManagementSystemlogs,software
programs,orotherevidence(eitherinhardcopyorelectronicformat)todemonstrate
compliancewithRequirementR2.
D. Compliance
1.

ComplianceMonitoringProcess
1.1. ComplianceEnforcementAuthority
AsdefinedintheNERCRulesofProcedure,“ComplianceEnforcementAuthority”
meansNERCortheRegionalEntityintheirrespectiverolesofmonitoringand
enforcingcompliancewiththeNERCReliabilityStandards.
1.2. DataRetention
Thefollowingevidenceretentionperiodsidentifytheperiodoftimeanentityis
requiredtoretainspecificevidencetodemonstratecompliance.Forinstances
wheretheevidenceretentionperiodspecifiedbelowisshorterthanthetime
sincethelastaudit,thecomplianceenforcementauthoritymayaskanentityto
provideotherevidencetoshowthatitwascompliantforthefullͲtimeperiod
sincethelastaudit.
TheResponsibleEntityshallretaindataorevidencetoshowcomplianceforthe
currentyear,plusthreepreviouscalendaryearsunless,directedbyits
complianceenforcementauthority,toretainspecificevidenceforalonger
periodoftimeaspartofaninvestigation.Datarequiredforthecalculationof
RegulationReserveSharingGroupReportingAce,orReportingACE,CPS1,and
BAALshallberetainedindigitalformatatthesamescanrateatwhichthe
ReportingACEiscalculatedforthecurrentyear,plusthreepreviouscalendar
years.
IfaResponsibleEntityisfoundnoncompliant,itshallkeepinformationrelatedto
thenoncomplianceuntilfoundcompliant,orforthetimeperiodspecifiedabove,
whicheverislonger.
Thecomplianceenforcementauthorityshallkeepthelastauditrecordsandall
subsequentrequestedandsubmittedrecords.
1.3. ComplianceMonitoringandAssessmentProcesses
ComplianceAudits
SelfͲCertifications
SpotChecking
ComplianceInvestigation
SelfͲReporting
Complaints

BALͲ001Ͳ2
January1,2013



Page6of13



StandardBALͲ001Ͳ2–RealPowerBalancingControlPerformance
1.4. AdditionalComplianceInformation
None.
2.

ViolationSeverityLevels
R
#

Lower VSL

R1 TheCPS1value
ofthe
Responsible
Entity,ona
rolling12Ͳ
monthbasis,is
lessthan100
percentbut
greaterthanor
equalto95
percentforthe
applicable
Interconnection.
R2 TheBalancing
Authority
exceededits
clockͲminute
BAALformore
than30
consecutive
clockminutes
butfor45
consecutive
clockminutesor
less.

Moderate VSL

High VSL

Severe VSL

TheCPS1value
ofthe
Responsible
Entity,ona
rolling12Ͳ
monthbasis,is
lessthan95
percent,but
greaterthanor
equalto90
percentforthe
applicable
Interconnection.
TheBalancing
Authority
exceededits
clockͲminute
BAALforgreater
than45
consecutive
clockminutes
butfor60
consecutive
clockminutesor
less.

TheCPS1value
ofthe
Responsible
Entity,ona
rolling12Ͳ
monthbasis,is
lessthan90
percent,but
greaterthanor
equalto85
percentforthe
applicable
Interconnection.
TheBalancing
Authority
exceededits
clockͲminute
BAALforgreater
than60
consecutive
clockminutes
butfor75
consecutive
clockminutesor
less.

TheCPS1valueofthe
ResponsibleEntity,ona
rolling12Ͳmonthbasis,
islessthan85percent
fortheapplicable
Interconnection.

TheBalancingAuthority
exceededitsclockͲ
minuteBAALforgreater
than75consecutive
clockͲminutes.

E. RegionalVariances
None.
F. AssociatedDocuments
BALͲ001Ͳ2,RealPowerBalancingControlPerformanceStandardBackgroundDocument
VersionHistory
Version
0

BALͲ001Ͳ2
January1,2013

Date

Action

ChangeTracking

February8,

BOTApproval

New



Page7of13



StandardBALͲ001Ͳ2–RealPowerBalancingControlPerformance
2005
0

April1,2005

EffectiveImplementationDate

New

0

August8,2005

Removed“Proposed”fromEffectiveDate

Errata

0

July24,2007

CorrectedR3toreferenceM1andM2
insteadofR1andR2

Errata

0a

December19,
2007

AddedAppendix2–InterpretationofR1
approvedbyBOTonOctober23,2007

Revised

0a

January16,
2008

InSectionA.2.,Added“a”toendof
standardnumber
InSectionF,correctedautomatic
numberingfrom“2”to“1”andremoved
“approved”andaddedparenthesisto
“(October23,2007)”

Errata

0

January23,
2008

ReversederratachangefromJuly24,2007

Errata

0.1a

October29,
2008

Boardapprovederratachanges;updated
versionnumberto“0.1a”

Errata

0.1a

May13,2009

ApprovedbyFERC





InclusionofBAALandWECCVarianceand
exclusionofCPS2

Revision

1

BALͲ001Ͳ2
January1,2013



Page8of13



StandardBALͲ001Ͳ2–RealPowerBalancingControlPerformance
Attachment1
EquationsSupportingRequirementR1andMeasureM1

CPS1iscalculatedasfollows:

CPS1=(2ͲCF)*100%

ThefrequencyͲrelatedcompliancefactor(CF),isaratiooftheaccumulatingclockͲminute
complianceparametersforthemostrecentconsecutive12Ͳcalendarmonths,dividedby
thesquareofthetargetfrequencybound:
CF =

CF

12 Ͳ month

(ɸ1I ) 2

Whereɸ1Iistheconstantderivedfromatargetedfrequencyboundforeach
Interconnectionasfollows:
x

EasternInterconnectionɸ1I=0.018Hz

x

WesternInterconnectionɸ1I=0.0228Hz

x

ERCOTInterconnectionɸ1I=0.030Hz

x

QuebecInterconnectionɸ1I=0.021Hz

TheratingindexCF12Ͳmonthisderivedfromthemostrecentconsecutive12Ͳcalendarmonths
ofdata.TheaccumulatingclockͲminutecomplianceparametersarederivedfromtheoneͲ
minuteaveragesofReportingACE,FrequencyError,andFrequencyBiasSettings.
AclockͲminuteaverageistheaverageofthereportingBalancingAuthority’svalid
measuredvariable(i.e.,forReportingACE(RACE)andforFrequencyError)foreach
samplingcycleduringagivenclockminute.

§ RACE·
¨
¸
©  10 B ¹ clock-minute

§ ¦ RACE
sampling cycles in clock - minute
¨
¨
nsampling cycles in clock-minute
©
- 10B

·
¸
¸
¹

And,

¦ 'F

'Fclock -minute

sampling cycles in clock - minute

nsampling cycles in clock -minute

TheBalancingAuthority’sclockͲminutecompliancefactor(CFclockͲminute)calculationis:

BALͲ001Ͳ2
January1,2013



Page9of13



StandardBALͲ001Ͳ2–RealPowerBalancingControlPerformance

ª§ RACE·
º
* 'Fclock-minute »
¸
Ǭ
¬©  10 B ¹ clock-minute
¼

CFclock- minute

Normally,60clockͲminuteaveragesofthereportingBalancingAuthority’sReportingACE
andFrequencyErrorwillbeusedtocomputethehourlyaveragecompliancefactor(CFclockͲ
hour).

¦ CF

clock - minute

CFclock-hour

nclock-minute samples in hour

ThereportingBalancingAuthorityshallbeabletorecalculateandstoreeachofthe
respectiveclockͲhouraverages(CFclockͲhouraverageͲmonth)andthedatasamplesforeach24Ͳ
hourperiod(oneforeachclockͲhour;i.e.,hourending(HE)0100,HE0200,...,HE2400).
Tocalculatethemonthlycompliancefactor(CFmonth):

¦ [(CF
¦ [n

clock - hour

)( none -minute samples in clock -hour )]

days -in - month

CFclock - hour average -month

one - minute samples in clock - hour
days -in month

¦ [(CF

clock - hour average - month

CFmonth

hours -in - day

¦ [n

]

)( none - minute samples in clock - hour averages )]

one - minute samples in clock - hour averages

]

hours -in day

Tocalculatethe12Ͳmonthcompliancefactor(CF12month):
12

¦ (CF

month -i

CF12-month

)(none-minute samples in month i )]

i 1

12

¦ [n

( one - minute samples in month)-i

]

i 1

ToensurethattheaverageReportingACEandFrequencyErrorcalculatedforanyoneͲ
minuteintervalisrepresentativeofthattimeinterval,itisnecessarythatatleast50
percentofboththeReportingACEandFrequencyErrorsampledataduringtheoneͲ
minuteintervalisvalid.IftherecordingofReportingACEorFrequencyErrorisinterrupted
suchthatlessthan50percentoftheoneͲminutesampleperioddataisavailableorvalid,
thenthatoneͲminuteintervalisexcludedfromtheCPS1calculation.

ABalancingAuthorityprovidingOverlapRegulationServicetoanotherBalancingAuthority
calculatesitsCPS1performanceaftercombiningitsReportingACEandFrequencyBias
BALͲ001Ͳ2
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StandardBALͲ001Ͳ2–RealPowerBalancingControlPerformance
SettingswiththeReportingACEandFrequencyBiasSettingsoftheBalancingAuthority
receivingtheRegulationService.



BALͲ001Ͳ2
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StandardBALͲ001Ͳ2–RealPowerBalancingControlPerformance
Attachment2

EquationsSupportingRequirementR2andMeasureM2


WhenactualfrequencyisequaltoScheduledFrequency,BAALHighandBAALLowdonotapply.
WhenactualfrequencyislessthanScheduledFrequency,BAALHighdoesnotapply,and
BAALLowiscalculatedas:
BAAL Low

 10 Bi u FTL Low  FS u FTL Low  FS 
FA  FS 

WhenactualfrequencyisgreaterthanScheduledFrequency,BAALLowdoesnotapplyand
theBAALHighiscalculatedas:

BAALHigh

 10B u FTL
i

High

 FS u

FTL

High

 FS 

FA  FS 

Where:
BAALLowistheLowBalancingAuthorityACELimit(MW)
BAALHighistheHighBalancingAuthorityACELimit(MW)
10isaconstanttoconverttheFrequencyBiasSettingfromMW/0.1HztoMW/Hz
BiistheFrequencyBiasSettingforaBalancingAuthority(expressedasMW/0.1Hz)
FAisthemeasuredfrequencyinHz.
FSisthescheduledfrequencyinHz.
FTLLowistheLowFrequencyTriggerLimit(calculatedasFSͲ3ɸ1IHz)
FTLHighistheHighFrequencyTriggerLimit(calculatedasFS+3ɸ1IHz)
Whereɸ1Iistheconstantderivedfromatargetedfrequencyboundforeach
Interconnectionasfollows:

x

EasternInterconnectionɸ1I=0.018Hz

x

WesternInterconnectionɸ1I=0.0228Hz

x

ERCOTInterconnectionɸ1I=0.030Hz

x

QuebecInterconnectionɸ1I=0.021Hz


ToensurethattheaverageactualfrequencycalculatedforanyoneͲminuteintervalis
representativeofthattimeinterval,itisnecessarythatatleast50%oftheactual
frequencysampledataduringthatoneͲminuteintervalisvalid.Iftherecordingofactual
frequencyisinterruptedsuchthatlessthan50percentoftheoneͲminutesampleperiod
BALͲ001Ͳ2
January1,2013



Page12of13



StandardBALͲ001Ͳ2–RealPowerBalancingControlPerformance
dataisavailableorvalid,thenthatoneͲminuteintervalisexcludedfromtheBAAL
calculation.

ABalancingAuthorityprovidingOverlapRegulationServicetoanotherBalancingAuthority
calculatesitsBAALperformanceaftercombiningitsFrequencyBiasSettingwiththe
FrequencyBiasSettingoftheBalancingAuthorityreceivingRegulationService.


BALͲ001Ͳ2
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StandardBALͲ001Ͳ1BALͲ001Ͳ2–RealPowerBalancingControlPerformance

StandardDevelopmentRoadmap
Thissectionismaintainedbythedraftingteamduringthedevelopmentofthestandardandwill
beremovedwhenthestandardbecomeseffective.
DevelopmentStepsCompleted:
1. TheSARforProject2007Ͳ18,ReliabilityBasedControls,waspostedfora30Ͳdayformal
commentperiodonMay15,2007.
2. ArevisedSARforProject2007Ͳ05,ReliabilityBasedControls,waspostedforasecond
30ͲdayformalcommentperiodonSeptember10,2007.
3. TheStandardsCommitteeapprovedProject2007Ͳ18,ReliabilityBasedControls,tobe
movedtostandarddraftingonDecember11,2007.
4. TheSARforProject2007Ͳ05,BalancingAuthorityControls,waspostedfora30Ͳday
formalcommentperiodonJuly3,2007.
5. TheStandardsCommitteeapprovedProject2007Ͳ05,BalancingAuthorityControls,to
bemovedtostandarddraftingonJanuary18,2008.
6. TheStandardsCommitteeapprovedthemergerofProject2007Ͳ05,BalancingAuthority
Controls,andProject2007Ͳ18,ReliabilityͲbasedControls,asProject2010Ͳ14,Balancing
AuthorityReliabilityͲbasedControls,onJuly28,2010.
7. TheNERCStandardsCommitteeapprovedbreakingProject2010Ͳ14,Balancing
AuthorityReliabilityͲbasedControls,intotwophases;andmovingPhase1(Project2010Ͳ
14.1,BalancingAuthorityReliabilityͲbasedControls–Reserves)intoformalstandards
developmentonJuly13,2011.
8. Thedraftstandardwaspostedfor30ͲdayformalindustrycommentperiodfromJune4,
2012throughJuly3,2012.
ProposedActionPlanandDescriptionofCurrentDraft:
Thisisthesecondpostingoftheproposednewstandard.Thisproposeddraftstandardwillbe
postedfora45ͲdayformalcommentperiodbeginningonMarch12,2013throughApril25,
2013.

FutureDevelopmentPlan:
AnticipatedActions
1. Secondposting

AnticipatedDate
March/April2013

2. InitialBallot

April2013

3. RecirculationBallot

October2013

4. NERCBOTadoption.

November2013

BALͲ001Ͳ1BALͲ001Ͳ2
January1,2013



Page1of15



StandardBALͲ001Ͳ1BALͲ001Ͳ2–RealPowerBalancingControlPerformance

DefinitionsofTermsUsedinStandard
Thissectionincludesallnewlydefinedorrevisedtermsusedintheproposedstandard.Terms
alreadydefinedintheReliabilityStandardsGlossaryofTermsarenotrepeatedhere.Newor
reviseddefinitionslistedbelowbecomeapprovedwhentheproposedstandardisapproved.
Whenthestandardbecomeseffective,thesedefinedtermswillberemovedfromtheindividual
standardandaddedtotheGlossary.
RegulationReserveSharingGroup:AgroupwhosemembersconsistoftwoormoreBalancing
Authoritiesthatcollectivelymaintain,allocate,andsupplyoperatingtheregulatingreserve
requiredforeachallmemberBalancingmemberBalancingAuthorityiestouseinmeeting
theapplicableregulatingstandardsrequirementsassociatedwithControlPerformanceStandard
1.
RegulationReserveSharingGroupReportingACE:Atanygiventimeofmeasurementforthe
applicableRegulationReserveSharingGroup,thealgebraicsumoftheReportingACEs(as
calculatedatsuchtimeofmeasurement)ofalltheBalancingAuthoritiesparticipatinginthat
makeuptheRegulationReserveSharingGroupatthetimeofmeasurement.Balancing
AuthorityACELimit(BAAL):ThelimitbeyondwhichaBalancingAuthoritycontributesmore
thanitsshareofInterconnectionfrequencycontrolreliabilityrisk.Thisdefinitionappliestoa
highlimit(BAALHigh)andalowlimit(BAALLow).

ReportingACE:ThescanratevaluesofaBalancingAuthority’sAreaControlError(ACE)
measuredinMW,asdefinedinBALͲ001,whichincludesthedifferencebetweentheBalancing
Authority’snetactualInterchangeanditsscheduledInterchange,plusitsFrequencyBias
obligation,plusanyknownmetererrorplusAutomaticTimeErrorCorrection(ATEC–If
operatingintheWesternInterconnectionandintheATECmode).
ReportingACEiscalculatedasfollows:



ReportingACE=(NIAоNIS)о10B(FAоFS)оIME+IATEC


Where:
NIA(ActualNetInterchange)isthealgebraicsumofactualmegawatttransfersacrossall
TieLinesandincludesPseudoͲTies.BalancingAuthoritiesdirectlyconnectedvia
asynchronoustiestoanotherInterconnectionmayincludeorexcludemegawatt
transfersonthosetielinesintheiractualinterchange,providedtheyareimplemented
inthesamemannerforNetInterchangeSchedule.
NIS(ScheduledNetInterchange)isthealgebraicsumofallscheduledmegawatt
transfers,includingDynamicSchedules,withadjacentBalancingAuthorities,andtaking
intoaccounttheeffectsofscheduleramps.BalancingAuthoritiesdirectlyconnectedvia
BALͲ001Ͳ1BALͲ001Ͳ2
January1,2013



Page2of15



StandardBALͲ001Ͳ1BALͲ001Ͳ2–RealPowerBalancingControlPerformance
asynchronoustiestoanotherInterconnectionmayincludeorexcludemegawatt
transfersonthosetielinesintheirscheduledInterchange,providedtheyare
implementedinthesamemannerforNetInterchangeActual.
B(FrequencyBiasSetting)istheFrequencyBiasSetting(innegativeMW/0.1Hz)forthe
BalancingAuthority.
10istheconstantfactorthatconvertsthefrequencybiassettingunitstoMW/Hz.
FA(ActualFrequency)isthemeasuredfrequencyinHz.
FS(ScheduledFrequency)is60.0Hz,exceptduringatimecorrection.
IME(InterchangeMeterError)isthemetererrorcorrectionfactorandrepresentsthe
differencebetweentheintegratedhourlyaverageofthenetinterchangeactual(NIA)
andthecumulativehourlynetInterchangeenergymeasurement(inmegawattͲhours).
IATEC(AutomaticTimeErrorCorrection)istheadditionofacomponenttotheACE
equationthatmodifiesthecontrolpointforthepurposeofcontinuouslypayingback
PrimaryInadvertentInterchangetocorrectaccumulatedtimeerror.AutomaticTime
ErrorCorrectionisonlyapplicableintheWesterninterconnection.
on/off peak

IATEC

PII

accum

1  Y * H

whenoperatinginAutomaticTimeErrorCorrectioncontrolmode.

IATECshallbezerowhenoperatinginanyotherAGCmode.
x

Y=B/BS.

x

H=NumberofHoursusedtopaybackPrimaryInadvertentInterchangeenergy.The
valueofHissetto3.

x

BS=FrequencyBiasfortheInterconnection(MW/0.1Hz).

x

PrimaryInadvertentInterchange(PIIhourly)is(1ͲY)*(IIactualͲB*ȴTE/6)

x

IIactualisthehourlyInadvertentInterchangeforthelasthour.

x

ȴTEisthehourlychangeinsystemTimeErrorasdistributedbytheInterconnection
TimeMonitor.Where:



ȴTE=TEendhour–TEbeginhour–TDadj–(t)*(TEoffset)

x

TDadjistheReliabilityCoordinatoradjustmentfordifferenceswithInterconnection
TimeMonitorcontrolcenterclocks.

x

tisthenumberofminutesofManualTimeErrorCorrectionthatoccurredduringthe
hour.

x

TEoffsetis0.000or+0.020orͲ0.020.

x

PIIaccumistheBalancingAuthority’saccumulatedPIIhourlyinMWh.AnOnͲPeakand
OffͲPeakaccumulationaccountingisrequired.

BALͲ001Ͳ1BALͲ001Ͳ2
January1,2013



Page3of15



StandardBALͲ001Ͳ1BALͲ001Ͳ2–RealPowerBalancingControlPerformance
Where:

PII

on/off peak
accum

=lastperiod’s

on/off peak

PII

accum

+PIIhourly


AllNERCInterconnectionswithmultipleBalancingAuthoritiesoperateusingtheprinciples
ofTieͲlineBias(TLB)ControlandrequiretheuseofanACEequationsimilartothe
ReportingACEdefinedabove.Anymodification(s)tothisspecifiedReportingACE
equationthatis(are)implementedforallBAsonaninterconnectionandis(are)consistent
withthefollowingfourprincipleswillprovideavalidalternativeReportingACEequation
consistentwiththemeasuresincludedinthisstandard.
1. Allportionsoftheinterconnectionareincludedinoneareaoranothersothat
thesumofallareageneration,loadsandlossesisthesameastotalsystem
generation,loadandlosses.
2. Thealgebraicsumofallareanetinterchangeschedulesandallnetinterchange
actualvaluesisequaltozeroatalltimes.
3. TheuseofacommonscheduledfrequencyFSforallareasatalltimes.
4. Theabsenceofmeteringorcomputationalerrors.(Theinclusionanduseofthe
IMEtermtoaccountforknownmeteringorcomputationalerrors.)

Interconnection:Whencapitalized,anyoneofthefourmajorelectricsystemnetworksinNorth
America:Eastern,Western,ERCOTTexasandQuebec.

BALͲ001Ͳ1BALͲ001Ͳ2
January1,2013



Page4of15



StandardBALͲ001Ͳ1BALͲ001Ͳ2–RealPowerBalancingControlPerformance
A. Introduction
1.

Title:

RealPowerBalancingControlPerformance

2.

Number:

BALͲ001Ͳ1BALͲ001Ͳ2

3.

Purpose:

TocontrolInterconnectionfrequencywithindefinedlimits.

4.

Applicability:
4.1. BalancingAuthority
4.1.1 ABalancingAuthorityreceivingOverlapRegulationServiceisnotsubject
toControlPerformanceStandard1(CPS1)orBalancingAuthorityACE
Limit(BAAL)complianceevaluation.
4.1.2 ABalancingAuthoritythatisamemberofaRegulationReserveSharing
GroupistheResponsibleEntityonlyinperiodduringwhichtheBalancing
Authorityisnotinactivestatusundertheapplicableagreementor
governingrulesfortheRegulationReserveSharingGroup.
4.2. RegulationReserveSharingGroup
4.1.1ABalancingAuthorityprovidingOverlapRegulationServicetoanotherBalancing
AuthoritycalculatesitsCPS1performanceaftercombiningitsReportingACEand
FrequencyBiasSettingswiththeReportingACE,andFrequencyBiasSettingsof
theBalancingAuthorityreceivingtheRegulationService.

ABalancingAuthorityprovidingOverlapRegulationServicetoanotherBalancingAuthority
calculatesitsBAALperformanceaftercombiningitsFrequencyBiasSettingwiththe
FrequencyBiasSettingoftheBalancingAuthorityreceivingRegulationService.
4.1.2 ABalancingAuthorityreceivingOverlapRegulationServiceisnotsubjectto
CPS1orBAALcomplianceevaluation.
5.

(Proposed)EffectiveDate:
5.1.

Firstdayofthefirstcalendarquarterthatissixmonthsbeyondthedatethat
thisstandardisapprovedbyapplicableregulatoryauthorities,orinthose
jurisdictionswhereregulatoryapprovalisnotrequired,thestandardbecomes
effectivethefirstdayofthefirstcalendarquarterthatissixmonthsbeyondthe
datethisstandardisapprovedbytheNERCBoardofTrustees’,orasotherwise
madepursuanttothelawsapplicabletosuchEROgovernmentalauthorities.



B. Requirements
R1.

TheResponsibleEntityEachBalancingAuthorityshalloperatesuchthattheBalancing
Authority’sControlPerformanceStandard1(CPS1),asapplicableandascalculatedin
accordancewithAttachment1,isgreaterthanorequalto100percentforthe
applicableInterconnectioninwhichitoperatesforeach12Ͳmonthperiod,evaluated
monthly,tosupportInterconnectionfrequency.[ViolationRiskFactor:Medium][Time
Horizon:RealͲtimeOperations]

BALͲ001Ͳ1BALͲ001Ͳ2
January1,2013



Page5of15



StandardBALͲ001Ͳ1BALͲ001Ͳ2–RealPowerBalancingControlPerformance
R2.

EachBalancingAuthorityshalloperatesuchthatitsclockͲminuteaverageofReporting
ACEdoesnotexceeditsclockͲminuteBalancingAuthorityACELimit(BAAL)formore
than30consecutiveclockͲminutesitsclockͲminuteBalancingAuthorityACELimit
(BAAL),ascalculatedinAttachment2,fortheapplicableInterconnectioninwhichthe
BalancingAuthorityitorRegulationReserveSharingGroupoperatestosupport
Interconnectionfrequency.[ViolationRiskFactor:Medium][TimeHorizon:RealͲtime
Operations]

C. Measures
M1. TheResponsibleEntityEachBalancingAuthorityshallprovideevidence,uponrequest,;
suchasdatedcalculationoutputfromspreadsheets,EnergyManagementSystem
logs,softwareprograms,orotherevidence(eitherinhardcopyorelectronicformat)
todemonstratecompliancewithRequirementR1.
M2. EachBalancingAuthorityshallprovideevidence,uponrequest,;suchasdated
calculationoutputfromspreadsheets,EnergyManagementSystemlogs,software
programs,orotherevidence(eitherinhardcopyorelectronicformat)todemonstrate
compliancewithRequirementR2.
D. Compliance
1.

ComplianceMonitoringProcess
1.1. ComplianceEnforcementAuthority
AsdefinedintheNERCRulesofProcedure,“ComplianceEnforcementAuthority”
meansNERCortheRegionalEntityintheirrespectiverolesofmonitoringand
enforcingcompliancewiththeNERCReliabilityStandards.Theregionalentityis
thecomplianceenforcementauthority,exceptwheretheresponsibleentity
worksfortheregionalentity.Wheretheresponsibleentityworksforthe
regionalentity,theregionalentitywillestablishanagreementwiththeERO,or
anotherentityapprovedbytheEROandFERC(i.e.,anotherregionalentity),to
beresponsibleforcomplianceenforcement.
1.2. DataRetention
Thefollowingevidenceretentionperiodsidentifytheperiodoftimeanentityis
requiredtoretainspecificevidencetodemonstratecompliance.Forinstances
wheretheevidenceretentionperiodspecifiedbelowisshorterthanthetime
sincethelastaudit,thecomplianceenforcementauthoritymayaskanentityto
provideotherevidencetoshowthatitwascompliantforthefullͲtimeperiod
sincethelastaudit.
TheResponsibleEntityBalancingAuthorityshallretaindataorevidencetoshow
complianceforthecurrentyear,plusthreepreviouscalendaryearsunless,
directedbyitscomplianceenforcementauthority,toretainspecificevidencefor
alongerperiodoftimeaspartofaninvestigation.Datarequiredforthe
calculationofRegulationReserveSharingGroupReportingAce,orReporting
ACE,CPS1,andBAALshallberetainedindigitalformatatthesamescanrateat

BALͲ001Ͳ1BALͲ001Ͳ2
January1,2013



Page6of15



StandardBALͲ001Ͳ1BALͲ001Ͳ2–RealPowerBalancingControlPerformance
whichtheReportingACEceiscalculatedforthecurrentyear,plusthreeprevious
calendaryears.
IfaResponsibleEntityBalancingAuthorityisfoundnoncompliant,itshallkeep
informationrelatedtothenoncomplianceuntilfoundcompliant,orforthetime
periodspecifiedabove,whicheverislonger.
Thecomplianceenforcementauthorityshallkeepthelastauditrecordsandall
subsequentrequestedandsubmittedrecords.
1.3. ComplianceMonitoringandAssessmentProcesses
ComplianceAudits
SelfͲCertifications
SpotChecking
ComplianceInvestigation
SelfͲReporting
Complaints
1.4. AdditionalComplianceInformation
None.
2.

ViolationSeverityLevels
R
#

Lower VSL

R1 TheCPS1value
ofthe
RResponsible
Entity,’sorthea
Balancing
Authority’s,
areavalueof
CPS1,ona
rolling12Ͳ
monthbasis,is
lessthan100
percentbut
greaterthanor
equalto95
percentforthe
applicable
Interconnection.
R2 TheBalancing
Authority
BALͲ001Ͳ1BALͲ001Ͳ2
January1,2013

Moderate VSL

High VSL

Severe VSL

TheCPS1value
ofthe
Responsible
Entity,ona
rolling12Ͳ
monthbasis,is
lessthan95
percent,but
greaterthanor
equalto90
percentforthe
applicable
Interconnection.

TheCPS1value
ofthe
Responsible
Entity,ona
rolling12Ͳ
monthbasis,is
lessthan90
percent,but
greaterthanor
equalto85
percentforthe
applicable
Interconnection.

TheCPS1valueofthe
ResponsibleEntity,ona
rolling12Ͳmonthbasis,
islessthan85percent
fortheapplicable
Interconnection.

TheBalancing
Authority

TheBalancing
Authority

TheBalancingAuthority
exceededitsclockͲ



Page7of15



StandardBALͲ001Ͳ1BALͲ001Ͳ2–RealPowerBalancingControlPerformance
exceededits
clockͲminute
BAALformore
than30
consecutive
clockminutes
butforlessthan
orequalto45
consecutive
clockminutesor
less.

exceededits
clockͲminute
BAALforgreater
than45
consecutive
clockminutes
butforlessthan
orequalto60
consecutive
clockminutesor
less.

exceededits
minuteBAALforgreater
clockͲminute
than75consecutive
BAALforgreater clockͲminutes.
than60
consecutive
clockminutes
butforlessthan
orequalto75
consecutive
clockminutesor
less.

E. RegionalVariances
None.
F. AssociatedDocuments
BALͲ001Ͳ1BALͲ001Ͳ2,RealPowerBalancingControlPerformanceStandardBackground
Document
VersionHistory
Version

Date

Action

ChangeTracking

0

February8,
2005

BOTApproval

New

0

April1,2005

EffectiveImplementationDate

New

0

August8,2005

Removed“Proposed”fromEffectiveDate

Errata

0

July24,2007

CorrectedR3toreferenceM1andM2
insteadofR1andR2

Errata

0a

December19,
2007

AddedAppendix2–InterpretationofR1
approvedbyBOTonOctober23,2007

Revised

0a

January16,
2008

InSectionA.2.,Added“a”toendof
standardnumber
InSectionF,correctedautomatic
numberingfrom“2”to“1”andremoved
“approved”andaddedparenthesisto
“(October23,2007)”

Errata

0

January23,
2008

ReversederratachangefromJuly24,2007

Errata

0.1a

October29,
2008

Boardapprovederratachanges;updated
versionnumberto“0.1a”

Errata

BALͲ001Ͳ1BALͲ001Ͳ2
January1,2013



Page8of15



StandardBALͲ001Ͳ1BALͲ001Ͳ2–RealPowerBalancingControlPerformance
0.1a

1

BALͲ001Ͳ1BALͲ001Ͳ2
January1,2013

May13,2009

ApprovedbyFERC





InclusionofBAALandWECCVarianceand
exclusionofCPS2

Revision



Page9of15



StandardBALͲ001Ͳ1BALͲ001Ͳ2–RealPowerBalancingControlPerformance
Attachment1
EquationsSupportingRequirementR1andMeasureM1

CPS1iscalculatedasfollows:

CPS1=(2ͲCF)*100%

ThefrequencyͲrelatedcompliancefactor(CF),isaratiooftheaccumulatingclockͲminute
complianceparametersforthemostrecentconsecutiveovera12Ͳcalendarmonthsperiod,
dividedbythesquareofthetargetfrequencybound:
CF =

CF

12 Ͳ month

(ɸ1I ) 2

whereWhereɸ1Iistheconstantderivedfromatargetedfrequencyboundforeach
Interconnectionasfollows:
x

EasternInterconnectionɸ1I=0.018Hz

x

WesternInterconnectionɸ1I=0.0228Hz

x

ERCOTInterconnectionɸ1I=0.030Hz

x

QuebecInterconnectionɸ1I=0.021Hz

TheratingindexCF12Ͳmonthisderivedfromthemostrecentconsecutive12Ͳcalendarmonths
ofdata.TheaccumulatingclockͲminutecomplianceparametersarederivedfromtheoneͲ
minuteaveragesofReportingACE,FrequencyError,andFrequencyBiasSettings.

ReportingACEiscalculatedasfollows:
ReportingACE=(NIAоNIS)о10B(FAоFS)оNME
Where:
NIA(NetInterchangeActual)isthealgebraicsumofactualmegawatttransfers
acrossallTieLinesandincludesPseudoͲTies.BalancingAuthoritiesdirectly
connectedviaasynchronoustiestoanotherInterconnectionmayincludeor
excludemegawatttransfersonthosetielinesintheiractualinterchange,
providedtheyareimplementedinthesamemannerforNetInterchange
Schedule.
NIS(NetInterchangeSchedule)isthealgebraicsumofallscheduledmegawatt
transfers,includingDynamicSchedules,withadjacentBalancingAuthorities,and
BALͲ001Ͳ1BALͲ001Ͳ2
January1,2013



Page10of15



StandardBALͲ001Ͳ1BALͲ001Ͳ2–RealPowerBalancingControlPerformance
takingintoaccounttheeffectsofscheduleramps.BalancingAuthoritiesdirectly
connectedviaasynchronoustiestoanotherInterconnectionmayincludeor
excludemegawatttransfersonthosetielinesintheirscheduledInterchange,
providedtheyareimplementedinthesamemannerforNetInterchangeActual.
B(FrequencyBiasSetting)istheFrequencyBiasSetting(innegativeMW/0.1Hz)
fortheBalancingAuthority.
10istheconstantfactorthatconvertsthefrequencybiassettingunitsto
MW/Hz.
FA(ActualFrequency)isthemeasuredfrequencyinHz,withminimumresolution
of+/Ͳ0.0005Hz.
FS(ScheduledFrequency)is60.0Hz,exceptduringatimecorrection.
NME(NetMeterError)isthemetererrorcorrectionfactorandrepresentsthe

differencebetweentheintegratedhourlyaverageofthenetinterchangeactual
(NIA)andthecumulativehourlynetInterchangeenergymeasurement(in
megawattͲhours).

AclockͲminuteaverageistheaverageofthereportingBalancingAuthority’svalid
measuredvariable(i.e.,forReportingACE(RACE)andforFrequencyError)foreach
samplingcycleduringagivenclockminute.

§ RACE·
¨
¸
©  10 B ¹ clock-minute

§ ¦ RACE
sampling cycles in clock - minute
¨
¨
nsampling cycles in clock-minute
©
- 10B

·
¸
¸
¹

§ ACE ·
¸
¨
©  10 B ¹ clock -minute

§ ¦ ACEsampling cycles in clock -minute
¨
¨
nsampling cycles in clock -minute
©
- 10B

·
¸
¸
¹

andAnd,

¦ 'F

'Fclock -minute

sampling cycles in clock - minute

nsampling cycles in clock -minute

TheBalancingAuthority’sclockͲminutecompliancefactor(CFclockͲminute)calculationis:

BALͲ001Ͳ1BALͲ001Ͳ2
January1,2013

CFclock- minute

ª§ RACE·
º
* 'Fclock-minute »
¸
Ǭ
¬©  10 B ¹ clock-minute
¼

CFclock-minute

ª§ ACE ·
º
* 'Fclock-minute »
¸
Ǭ
¬©  10 B ¹ clock-minute
¼


Page11of15



StandardBALͲ001Ͳ1BALͲ001Ͳ2–RealPowerBalancingControlPerformance

Normally,60clockͲminuteaveragesofthereportingBalancingAuthority’sReportingACE
andFrequencyErrorwillbeusedtocomputethehourlyaveragecompliancefactor(CFclockͲ
hour).

¦ CF

clock - minute

CFclock-hour

nclock-minute samples in hour

ThereportingBalancingAuthorityshallbeabletorecalculateandstoreeachofthe
respectiveclockͲhouraverages(CFclockͲhouraverageͲmonth)andthedatasamplesforeach24Ͳ
hourperiod(oneforeachclockͲhour;i.e.,hourending(HE)0100,HE0200,...,HE2400).
Tocalculatethemonthlycompliancefactor(CFmonth):

¦ [(CF
¦ [n

clock - hour

)( none -minute samples in clock -hour )]

days -in - month

CFclock - hour average -month

one - minute samples in clock - hour
days -in month

¦ [(CF

clock - hour average - month

CFmonth

hours - in - day

¦ [n

]

)( none - minute samples in clock - hour averages )]

one - minute samples in clock - hour averages

]

hours - in day

Tocalculatethe12Ͳmonthcompliancefactor(CF12month):
12

¦ (CF

month -i

CF12-month

)(none-minute samples in month i )]

i 1

12

¦ [n

( one - minute samples in month)-i

]

i 1

ToensurethattheaverageReportingACEandFrequencyErrorcalculatedforanyoneͲ
minuteintervalisrepresentativeofthattimeinterval,itisnecessarythatatleast50
percentofboththeReportingACEandFrequencyErrorsampledataduringtheoneͲ
minuteintervalisvalid.IftherecordingofReportingACEorFrequencyErrorisinterrupted
suchthatlessthan50percentoftheoneͲminutesampleperioddataisavailableorvalid,
thenthatoneͲminuteintervalisexcludedfromtheCPS1calculation.

ABalancingAuthorityprovidingOverlapRegulationServicetoanotherBalancingAuthority
calculatesitsCPS1performanceaftercombiningitsReportingACEandFrequencyBias
SettingswiththeReportingACEandFrequencyBiasSettingsoftheBalancingAuthority
receivingtheRegulationService.

BALͲ001Ͳ1BALͲ001Ͳ2
January1,2013



Page12of15



StandardBALͲ001Ͳ1BALͲ001Ͳ2–RealPowerBalancingControlPerformance
ABalancingAuthorityreceivingOverlapRegulationServiceisnotsubjectto
CPS1complianceevaluation.


BALͲ001Ͳ1BALͲ001Ͳ2
January1,2013



Page13of15



StandardBALͲ001Ͳ1BALͲ001Ͳ2–RealPowerBalancingControlPerformance
Attachment2

EquationsSupportingRequirementR2andMeasureM2


WhenactualfrequencyisequaltoScheduledFrequency60Hz,BAALHighandBAALLowdonot
apply.
WhenactualfrequencyislessthanScheduledFrequency60Hz,BAALHighdoesnotapply,and
BAALLowiscalculatedas:
BAAL Low
BAAL Low

 10 Bi u FTL Low  FS u FTL Low  FS 
FA  FS 
 10 Bi u FTL Low  60  u FTL Low  60 
FA  60 

WhenactualfrequencyisgreaterthanScheduledFrequency60Hz,BAALLowdoesnotapply
andtheBAALHighiscalculatedas:

BAALHigh

 10B u FTL

BAALHigh

 10B u FTL

i

i

High

High

 FS u

 60u

FTL

 FS 

FTL

 60

High

FA  FS 
High

FA  60

Where:
BAALLowistheLowBalancingAuthorityACELimit(MW)
BAALHighistheHighBalancingAuthorityACELimit(MW)
10isaconstanttoconverttheFrequencyBiasSettingfromMW/0.1HztoMW/Hz
BiistheFrequencyBiasSettingforaBalancingAuthority(expressedasMW/0.1Hz)
FAisthemeasuredfrequencyinHz,withaminimumresolutionof+/Ͳ0.0005Hz.
FSisthescheduledfrequencyinHz.
FTLLowistheLowFrequencyTriggerLimit(calculatedasFS60Ͳ3ɸ1IHz)
FTLHighistheHighFrequencyTriggerLimit(calculatedasFS60+3ɸ1IHz)
Whereɸ1Iistheconstantderivedfromatargetedfrequencyboundforeach
Interconnectionasfollows:

BALͲ001Ͳ1BALͲ001Ͳ2
January1,2013

x

EasternInterconnectionɸ1I=0.018Hz

x

WesternInterconnectionɸ1I=0.0228Hz

x

ERCOTInterconnectionɸ1I=0.030Hz



Page14of15



StandardBALͲ001Ͳ1BALͲ001Ͳ2–RealPowerBalancingControlPerformance

x QuebecInterconnectionɸ1I=0.021Hz

ToensurethattheaverageactualfrequencycalculatedforanyoneͲminuteintervalis
representativeofthattimeinterval,itisnecessarythatatleast50%oftheactual
frequencysampledataduringthatoneͲminuteintervalisvalid.Iftherecordingofactual
frequencyisinterruptedsuchthatlessthan50percentoftheoneͲminutesampleperiod
dataisavailableorvalid,thenthatoneͲminuteintervalisexcludedfromtheBAAL
calculation.

ABalancingAuthorityprovidingOverlapRegulationServicetoanotherBalancingAuthority
calculatesitsBAALperformanceaftercombiningitsFrequencyBiasSettingwiththe
FrequencyBiasSettingoftheBalancingAuthorityreceivingRegulationService.

ABalancingAuthorityreceivingOverlapRegulationServiceisnotsubjecttoBAAL
complianceevaluation.

BALͲ001Ͳ1BALͲ001Ͳ2
January1,2013



Page15of15



Implementation Plan

Project 2010-14.1 Balancing Authority Reliability-based Controls
- Reserves
ImplementationPlanforBALͲ001Ͳ2–RealPowerBalancingControlPerformance

ApprovalsRequired
BALͲ001Ͳ2–RealPowerBalancingControlPerformance

PrerequisiteApprovals
None

RevisionstoGlossaryTerms
ThefollowingdefinitionsshallbecomeeffectivewhenBALͲ001Ͳ2becomeseffective:

RegulationReserveSharingGroup:AgroupwhosemembersconsistoftwoormoreBalancing
Authoritiesthatcollectivelymaintain,allocate,andsupplytheregulatingreserverequiredfor
allmemberBalancingAuthoritiestouseinmeetingapplicableregulatingstandards.




RegulationReserveSharingGroupReportingACE:Atanygiventimeofmeasurementforthe
applicableRegulationReserveSharingGroup,thealgebraicsumoftheReportingACEs(as
calculatedatsuchtimeofmeasurement)oftheBalancingAuthoritiesparticipatinginthe
RegulationReserveSharingGroupatthetimeofmeasurement.

ReportingACE:ThescanratevaluesofaBalancingAuthority’sAreaControlError(ACE)
measuredinMW,whichincludesthedifferencebetweentheBalancingAuthority’snetactual
InterchangeanditsscheduledInterchange,plusitsFrequencyBiasobligation,plusanyknown
metererror.

ReportingACEiscalculatedasfollows:

ReportingACE=(NIAоNIS)о10B(FAоFS)оIME


Where:

NIA(ActualNetInterchange)isthealgebraicsumofactualmegawatttransfersacrossall
TieLinesandincludesPseudoͲTies.BalancingAuthoritiesdirectlyconnectedvia
asynchronoustiestoanotherInterconnectionmayincludeorexcludemegawatt
transfersonthosetielinesintheiractualinterchange,providedtheyareimplemented
inthesamemannerforNetInterchangeSchedule.
NIS(ScheduledNetInterchange)isthealgebraicsumofallscheduledmegawatt
transfers,includingDynamicSchedules,withadjacentBalancingAuthorities,andtaking
intoaccounttheeffectsofscheduleramps.BalancingAuthoritiesdirectlyconnectedvia
asynchronoustiestoanotherInterconnectionmayincludeorexcludemegawatt
transfersonthosetielinesintheirscheduledInterchange,providedtheyare
implementedinthesamemannerforNetInterchangeActual.
B(FrequencyBiasSetting)istheFrequencyBiasSetting(innegativeMW/0.1Hz)forthe
BalancingAuthority.
10istheconstantfactorthatconvertsthefrequencybiassettingunitstoMW/Hz.
FA(ActualFrequency)isthemeasuredfrequencyinHz.
FS(ScheduledFrequency)is60.0Hz,exceptduringatimecorrection.
IME(InterchangeMeterError)isthemetererrorcorrectionfactorandrepresentsthe
differencebetweentheintegratedhourlyaverageofthenetinterchangeactual(NIA)
andthecumulativehourlynetInterchangeenergymeasurement(inmegawattͲhours).

AllNERCInterconnectionswithmultipleBalancingAuthoritiesoperateusingtheprinciples
ofTieͲlineBias(TLB)ControlandrequiretheuseofanACEequationsimilartotheReporting
ACEdefinedabove.Anymodification(s)tothisspecifiedReportingACEequationthat
is(are)implementedforallBAsonaninterconnectionandis(are)consistentwiththe
followingfourprincipleswillprovideavalidalternativeReportingACEequationconsistent
withthemeasuresincludedinthisstandard.
1. Allportionsoftheinterconnectionareincludedinoneareaoranothersothatthe
sumofallareageneration,loadsandlossesisthesameastotalsystemgeneration,
loadandlosses.
2. Thealgebraicsumofallareanetinterchangeschedulesandallnetinterchange
actualvaluesisequaltozeroatalltimes.
3. TheuseofacommonscheduledfrequencyFSforallareasatalltimes.
4. Theabsenceofmeteringorcomputationalerrors.(TheinclusionanduseoftheIME
termtoaccountforknownmeteringorcomputationalerrors.)
Interconnection:Whencapitalized,anyoneofthefourmajorelectricsystemnetworksinNorth
America:Eastern,Western,ERCOTandQuebec.


BALͲ001Ͳ2–RealPowerBalancingControlPerformance
February,2013

2

TheexistingdefinitionofInterconnectionshouldberetiredatmidnightofthedayimmediatelypriorto
theeffectivedateofBALͲ001Ͳ2,inthejurisdictioninwhichthenewstandardisbecomingeffective.

Theproposedreviseddefinitionfor“Interconnection”isincorporatedintheNERCapprovedstandards,
detailedinAttachment1ofthisdocument.

ApplicableEntities
BalancingAuthority
RegulationReserveSharingGroup

ApplicableFacilities
N/A

ConformingChangestoOtherStandards
None

EffectiveDates
BALͲ001Ͳ2shallbecomeeffectiveasfollows:

Firstdayofthefirstcalendarquarterthatissixmonthsbeyondthedatethatthisstandardis
approved by applicable regulatory authorities, or in those jurisdictions where regulatory
approval is not required, the standard becomes effective the first day of the first calendar
quarter that is six months beyond the date this standard is approved by the NERC Board of
Trustees, or as otherwise made effective pursuant to the laws applicable to such ERO
governmentalauthorities. 

Justification
ThesixͲmonthperiodforimplementationofBALͲ001Ͳ2willprovideampletimeforBalancing
AuthoritiestomakenecessarymodificationstoexistingsoftwareprogramstoperformtheBAAL
calculationsforcompliance.

Retirements

BALͲ001Ͳ2–RealPowerBalancingControlPerformance
February,2013

3

BALͲ001Ͳ0.1a–RealPowerBalancingControlPerformanceshouldberetiredatmidnightoftheday
immediatelypriortotheeffectivedateofBALͲ001Ͳ2intheparticularjurisdictioninwhichthenew
standardisbecomingeffective.


BALͲ001Ͳ2–RealPowerBalancingControlPerformance
February,2013

4

Attachment1
ApprovedStandardsIncorporatingtheTerm“Interconnection”

BALͲ001Ͳ0.1a—RealPowerBalancingControlPerformance
BALͲ002Ͳ0—DisturbanceControlPerformance
BALͲ002Ͳ1—DisturbanceControlPerformance
BALͲ003Ͳ0.1b—FrequencyResponseandBias
BALͲ004Ͳ0—TimeErrorCorrection
BALͲ004Ͳ1—TimeErrorCorrection
BALͲ004ͲWECCͲ01—AutomaticTimeErrorCorrection
BALͲ005Ͳ0.1b—AutomaticGenerationControl
BALͲ006Ͳ2—InadvertentInterchange
WECCStandardBALͲSTDͲ002Ͳ1ͲOperatingReserves
CIPͲ001Ͳ1a—SabotageReporting
CIPͲ001Ͳ2a—SabotageReporting
CIP–002–4—CyberSecurity—CriticalCyberAssetIdentification
CIP–005–3a—CyberSecurity—ElectronicSecurityPerimeter(s)
COMͲ001Ͳ1.1—Telecommunications
EOPͲ001Ͳ2b—EmergencyOperationsPlanning
EOPͲ002Ͳ2.1—CapacityandEnergyEmergencies
EOPͲ002Ͳ3—CapacityandEnergyEmergencies
EOPͲ003Ͳ1—LoadSheddingPlans
EOPͲ003Ͳ2—LoadSheddingPlans
EOPͲ004Ͳ1—DisturbanceReporting
EOPͲ005Ͳ1—SystemRestorationPlans
EOPͲ005Ͳ2—SystemRestorationfromBlackstartResources
EOPͲ006Ͳ1—ReliabilityCoordination—SystemRestoration
EOPͲ006Ͳ2—SystemRestorationCoordination
FACͲ008Ͳ3—FacilityRatings
FACͲ010Ͳ2—SystemOperatingLimitsMethodologyforthePlanningHorizon
FACͲ011Ͳ2—SystemOperatingLimitsMethodologyfortheOperationsHorizon
INTͲ005Ͳ3—InterchangeAuthorityDistributesArrangedInterchange
INTͲ006Ͳ3—ResponsetoInterchangeAuthority
INTͲ008Ͳ3—InterchangeAuthorityDistributesStatus
IROͲ001Ͳ1.1—ReliabilityCoordination—ResponsibilitiesandAuthorities
IROͲ001Ͳ2—ReliabilityCoordination—ResponsibilitiesandAuthorities
IROͲ002Ͳ1—ReliabilityCoordination—Facilities
IROͲ002Ͳ2—ReliabilityCoordination—Facilities
IROͲ004Ͳ1—ReliabilityCoordination—OperationsPlanning
IROͲ005Ͳ2a—ReliabilityCoordination—CurrentDayOperations

BALͲ001Ͳ2–RealPowerBalancingControlPerformance
February,2013

5

IROͲ005Ͳ3a—ReliabilityCoordination—CurrentDayOperations
IROͲ006Ͳ5—ReliabilityCoordination—TransmissionLoadingRelief
IROͲ006ͲEASTͲ1—TLRProcedurefortheEasternInterconnection
IROͲ014Ͳ1—Procedures,Processes,orPlanstoSupportCoordinationBetween
ReliabilityCoordinators
IROͲ014Ͳ2—CoordinationAmongReliabilityCoordinators
IROͲ015Ͳ1—NotificationsandInformationExchangeBetweenReliabilityCoordinators
IROͲ016Ͳ1—CoordinationofRealͲtimeActivitiesBetweenReliabilityCoordinators
MODͲ010Ͳ0—SteadyͲStateDataforTransmissionSystemModelingandSimulation
MODͲ011Ͳ0—RegionalSteadyͲStateDataRequirementsandReportingProcedures
MODͲ012Ͳ0—DynamicsDataforTransmissionSystemModelingandSimulation
MODͲ013Ͳ1—RRODynamicsDataRequirementsandReportingProcedures
MODͲ014Ͳ0—DevelopmentofInterconnectionͲSpecificSteadyStateSystemModels
MODͲ015Ͳ0—DevelopmentofInterconnectionͲSpecificDynamicsSystemModels
MODͲ015Ͳ0.1—DevelopmentofInterconnectionͲSpecificDynamicsSystem
Models
MODͲ030Ͳ02—FlowgateMethodology
PRCͲ001Ͳ1—SystemProtectionCoordination
PRCͲ006Ͳ1—AutomaticUnderfrequencyLoadShedding
TOPͲ002Ͳ2a—NormalOperationsPlanning
TOPͲ004Ͳ2—TransmissionOperations
TOPͲ005Ͳ1.1a—OperationalReliabilityInformation
TOPͲ005Ͳ2a—OperationalReliabilityInformation
TOPͲ008Ͳ1—ResponsetoTransmissionLimitViolations
VARͲ001Ͳ1—VoltageandReactiveControl
VARͲ001Ͳ2—VoltageandReactiveControl
VARͲ002Ͳ1.1b—GeneratorOperationforMaintainingNetworkVoltageSchedules


BALͲ001Ͳ2–RealPowerBalancingControlPerformance
February,2013

6

Implementation Plan

Project 2010-14.1 Balancing Authority Reliability-based Controls
- Reserves
ImplementationPlanforBALͲ001Ͳ12–RealPowerBalancingControlPerformance

ApprovalsRequired
BALͲ001Ͳ21–RealPowerBalancingControlPerformance

PrerequisiteApprovals
None

RevisionstoGlossaryTerms
ThefollowingdefinitionsshallbecomeeffectivewhenBALͲ001Ͳ21becomeseffective:

RegulationReserveSharingGroup:AgroupwhosemembersconsistoftwoormoreBalancing
Authoritiesthatcollectivelymaintain,allocate,andsupplytheregulatingreserverequiredfor
allmemberBalancingAuthoritiestouseinmeetingapplicableregulatingstandards.

RegulationReserveSharingGroupReportingACE:Atanygiventimeofmeasurementforthe
applicableRegulationReserveSharingGroup,thealgebraicsumoftheReportingACEs(as
calculatedatsuchtimeofmeasurement)oftheBalancingAuthoritiesparticipatinginthe
RegulationReserveSharingGroupatthetimeofmeasurement.
BalancingAuthorityACELimit(BAAL):ThelimitbeyondwhichaBalancingAuthority
contributesmorethanitsshareofInterconnectionfrequencycontrolreliabilityrisk.This
definitionappliestoahighlimit(BAALHigh)andalowlimit(BAALLow).


ReportingACE:ThescanratevaluesofaBalancingAuthority’sAreaControlError(ACE)
measuredinMW,asdefinedinBALͲ001,whichincludesthedifferencebetweentheBalancing
Authority’snetactualInterchangeanditsscheduledInterchange,plusitsFrequencyBias
obligation,plusanyknownmetererror.

ReportingACEiscalculatedasfollows:




ReportingACE=(NIAоNIS)о10B(FAоFS)оIME


Where:
NIA(ActualNetInterchange)isthealgebraicsumofactualmegawatttransfersacrossall
TieLinesandincludesPseudoͲTies.BalancingAuthoritiesdirectlyconnectedvia
asynchronoustiestoanotherInterconnectionmayincludeorexcludemegawatt
transfersonthosetielinesintheiractualinterchange,providedtheyareimplemented
inthesamemannerforNetInterchangeSchedule.
NIS(ScheduledNetInterchange)isthealgebraicsumofallscheduledmegawatt
transfers,includingDynamicSchedules,withadjacentBalancingAuthorities,andtaking
intoaccounttheeffectsofscheduleramps.BalancingAuthoritiesdirectlyconnectedvia
asynchronoustiestoanotherInterconnectionmayincludeorexcludemegawatt
transfersonthosetielinesintheirscheduledInterchange,providedtheyare
implementedinthesamemannerforNetInterchangeActual.
B(FrequencyBiasSetting)istheFrequencyBiasSetting(innegativeMW/0.1Hz)forthe
BalancingAuthority.
10istheconstantfactorthatconvertsthefrequencybiassettingunitstoMW/Hz.
FA(ActualFrequency)isthemeasuredfrequencyinHz.
FS(ScheduledFrequency)is60.0Hz,exceptduringatimecorrection.
IME(InterchangeMeterError)isthemetererrorcorrectionfactorandrepresentsthe
differencebetweentheintegratedhourlyaverageofthenetinterchangeactual(NIA)
andthecumulativehourlynetInterchangeenergymeasurement(inmegawattͲhours).

AllNERCInterconnectionswithmultipleBalancingAuthoritiesoperateusingtheprinciples
ofTieͲlineBias(TLB)ControlandrequiretheuseofanACEequationsimilartotheReporting
ACEdefinedabove.Anymodification(s)tothisspecifiedReportingACEequationthat
is(are)implementedforallBAsonaninterconnectionandis(are)consistentwiththe
followingfourprincipleswillprovideavalidalternativeReportingACEequationconsistent
withthemeasuresincludedinthisstandard.
1. Allportionsoftheinterconnectionareincludedinoneareaoranothersothatthe
sumofallareageneration,loadsandlossesisthesameastotalsystemgeneration,
loadandlosses.
2. Thealgebraicsumofallareanetinterchangeschedulesandallnetinterchange
actualvaluesisequaltozeroatalltimes.
3. TheuseofacommonscheduledfrequencyFSforallareasatalltimes.
1.4. Theabsenceofmeteringorcomputationalerrors.(Theinclusionanduseofthe
IMEtermtoaccountforknownmeteringorcomputationalerrors.)

BALͲ001Ͳ2–RealPowerBalancingControlPerformance
February,2013

2

Interconnection:Whencapitalized,anyoneofthefourmajorelectricsystemnetworksinNorth
America:Eastern,Western,ERCOTTexasandQuebec.

TheexistingdefinitionofInterconnectionshouldberetiredatmidnightofthedayimmediatelypriorto
theeffectivedateofBALͲ001Ͳ12,inthejurisdictioninwhichthenewstandardisbecomingeffective.

Theproposedreviseddefinitionfor“Interconnection”isincorporatedintheNERCapprovedstandards,
detailedinAttachment1ofthisdocument.

ApplicableEntities
BalancingAuthority
RegulationReserveSharingGroup

ApplicableFacilities
N/A

ConformingChangestoOtherStandards
None

EffectiveDates
BALͲ001Ͳ12shallbecomeeffectiveasfollows:

Firstdayofthefirstcalendarquarterthatissixmonthsbeyondthedatethatthisstandardis
approved by applicable regulatory authorities, or in those jurisdictions where regulatory
approval is not required, the standard becomes effective the first day of the first calendar
quarter that is six months beyond the date this standard is approved by the NERC Board of
Trustees, or as otherwise made effective pursuant to the laws applicable to such ERO
governmentalauthorities. 

Justification
ThesixͲmonthperiodforimplementationofBALͲ001Ͳ12willprovideampletimeforBalancing
AuthoritiestomakenecessarymodificationstoexistingsoftwareprogramstoperformtheBAAL
calculationsforcompliance.


BALͲ001Ͳ2–RealPowerBalancingControlPerformance
February,2013

3

Retirements
BALͲ001Ͳ0.1a–RealPowerBalancingControlPerformanceshouldberetiredatmidnightoftheday
immediatelypriortotheeffectivedateofBALͲ001Ͳ12intheparticularjurisdictioninwhichthenew
standardisbecomingeffective.


BALͲ001Ͳ2–RealPowerBalancingControlPerformance
February,2013

4

Attachment1
ApprovedStandardsIncorporatingtheTerm“Interconnection”

BALͲ001Ͳ0.1a—RealPowerBalancingControlPerformance
BALͲ002Ͳ0—DisturbanceControlPerformance
BALͲ002Ͳ1—DisturbanceControlPerformance
BALͲ003Ͳ0.1b—FrequencyResponseandBias
BALͲ004Ͳ0—TimeErrorCorrection
BALͲ004Ͳ1—TimeErrorCorrection
BALͲ004ͲWECCͲ01—AutomaticTimeErrorCorrection
BALͲ005Ͳ0.1b—AutomaticGenerationControl
BALͲ006Ͳ2—InadvertentInterchange
WECCStandardBALͲSTDͲ002Ͳ1ͲOperatingReserves
CIPͲ001Ͳ1a—SabotageReporting
CIPͲ001Ͳ2a—SabotageReporting
CIP–002–4—CyberSecurity—CriticalCyberAssetIdentification
CIP–005–3a—CyberSecurity—ElectronicSecurityPerimeter(s)
COMͲ001Ͳ1.1—Telecommunications
EOPͲ001Ͳ2b—EmergencyOperationsPlanning
EOPͲ002Ͳ2.1—CapacityandEnergyEmergencies
EOPͲ002Ͳ3—CapacityandEnergyEmergencies
EOPͲ003Ͳ1—LoadSheddingPlans
EOPͲ003Ͳ2—LoadSheddingPlans
EOPͲ004Ͳ1—DisturbanceReporting
EOPͲ005Ͳ1—SystemRestorationPlans
EOPͲ005Ͳ2—SystemRestorationfromBlackstartResources
EOPͲ006Ͳ1—ReliabilityCoordination—SystemRestoration
EOPͲ006Ͳ2—SystemRestorationCoordination
FACͲ008Ͳ3—FacilityRatings
FACͲ010Ͳ2—SystemOperatingLimitsMethodologyforthePlanningHorizon
FACͲ011Ͳ2—SystemOperatingLimitsMethodologyfortheOperationsHorizon
INTͲ005Ͳ3—InterchangeAuthorityDistributesArrangedInterchange
INTͲ006Ͳ3—ResponsetoInterchangeAuthority
INTͲ008Ͳ3—InterchangeAuthorityDistributesStatus
IROͲ001Ͳ1.1—ReliabilityCoordination—ResponsibilitiesandAuthorities
IROͲ001Ͳ2—ReliabilityCoordination—ResponsibilitiesandAuthorities
IROͲ002Ͳ1—ReliabilityCoordination—Facilities
IROͲ002Ͳ2—ReliabilityCoordination—Facilities
IROͲ004Ͳ1—ReliabilityCoordination—OperationsPlanning
IROͲ005Ͳ2a—ReliabilityCoordination—CurrentDayOperations

BALͲ001Ͳ2–RealPowerBalancingControlPerformance
February,2013

5

IROͲ005Ͳ3a—ReliabilityCoordination—CurrentDayOperations
IROͲ006Ͳ5—ReliabilityCoordination—TransmissionLoadingRelief
IROͲ006ͲEASTͲ1—TLRProcedurefortheEasternInterconnection
IROͲ014Ͳ1—Procedures,Processes,orPlanstoSupportCoordinationBetween
ReliabilityCoordinators
IROͲ014Ͳ2—CoordinationAmongReliabilityCoordinators
IROͲ015Ͳ1—NotificationsandInformationExchangeBetweenReliabilityCoordinators
IROͲ016Ͳ1—CoordinationofRealͲtimeActivitiesBetweenReliabilityCoordinators
MODͲ010Ͳ0—SteadyͲStateDataforTransmissionSystemModelingandSimulation
MODͲ011Ͳ0—RegionalSteadyͲStateDataRequirementsandReportingProcedures
MODͲ012Ͳ0—DynamicsDataforTransmissionSystemModelingandSimulation
MODͲ013Ͳ1—RRODynamicsDataRequirementsandReportingProcedures
MODͲ014Ͳ0—DevelopmentofInterconnectionͲSpecificSteadyStateSystemModels
MODͲ015Ͳ0—DevelopmentofInterconnectionͲSpecificDynamicsSystemModels
MODͲ015Ͳ0.1—DevelopmentofInterconnectionͲSpecificDynamicsSystem
Models
MODͲ030Ͳ02—FlowgateMethodology
PRCͲ001Ͳ1—SystemProtectionCoordination
PRCͲ006Ͳ1—AutomaticUnderfrequencyLoadShedding
TOPͲ002Ͳ2a—NormalOperationsPlanning
TOPͲ004Ͳ2—TransmissionOperations
TOPͲ005Ͳ1.1a—OperationalReliabilityInformation
TOPͲ005Ͳ2a—OperationalReliabilityInformation
TOPͲ008Ͳ1—ResponsetoTransmissionLimitViolations
VARͲ001Ͳ1—VoltageandReactiveControl
VARͲ001Ͳ2—VoltageandReactiveControl
VARͲ002Ͳ1.1b—GeneratorOperationforMaintainingNetworkVoltageSchedules


BALͲ001Ͳ2–RealPowerBalancingControlPerformance
February,2013

6

StandardBALͲ002Ͳ2–ContingencyReserveforRecoveryfromaBalancingContingencyEvent
StandardDevelopmentRoadmap
Thissectionismaintainedbythedraftingteamduringthedevelopmentofthestandardandwill
beremovedwhenthestandardbecomeseffective.
DevelopmentStepsCompleted:
1. TheSARforProject2007Ͳ18,ReliabilityBasedControls,waspostedfora30Ͳdayformal
commentperiodonMay15,2007.
2. ArevisedSARforProject2007Ͳ05,ReliabilityBasedControls,waspostedforasecond
30ͲdayformalcommentperiodonSeptember10,2007.
3. TheStandardsCommitteeapprovedProject2007Ͳ18,ReliabilityBasedControls,tobe
movedtostandarddraftingonDecember11,2007.
4. TheSARforProject2007Ͳ05,BalancingAuthorityControls,waspostedfora30Ͳday
formalcommentperiodonJuly3,2007.
5. TheStandardsCommitteeapprovedProject2007Ͳ05,BalancingAuthorityControls,to
bemovedtostandarddraftingonJanuary18,2008.
6. TheStandardsCommitteeapprovedthemergerofProject2007Ͳ05,BalancingAuthority
Controls,andProject2007Ͳ18,ReliabilityͲbasedControl,asProject2010Ͳ14,Balancing
AuthorityReliabilityͲbasedControlsonJuly28,2010.
7. TheNERCStandardsCommitteeapprovedbreakingProject2010Ͳ14,Balancing
AuthorityReliabilityͲbasedControls,intotwophasesandmovingPhase1(Project2010Ͳ
14.1,BalancingAuthorityReliabilityͲbasedControls–Reserves)intoformalstandards
developmentonJuly13,2011.
8. Thedraftstandardwaspostedfor30ͲdayformalindustrycommentperiodfromJune4,
2012throughJuly3,2012

ProposedActionPlanandDescriptionofCurrentDraft:
Thisisthesecondpostingoftheproposednewstandard.Thisproposeddraftstandardwillbe
postedfora45ͲdayformalcommentperiodbeginningonMarch12,2013throughApril25,
2013.

FutureDevelopmentPlan:
AnticipatedActions
1. Secondposting

AnticipatedDate
March/April2013

2. InitialBallot

April2013

3. RecirculationBallot

October2013

4. NERCBOTadoption.

November2013

BALͲ002Ͳ2
February2013



Page1of8



StandardBALͲ002Ͳ2–ContingencyReserveforRecoveryfromaBalancingContingencyEvent


DefinitionsofTermsUsedinStandard
Thissectionincludesallnewlydefinedorrevisedtermsusedintheproposedstandard.Terms
alreadydefinedintheReliabilityStandardsGlossaryofTermsarenotrepeatedhere.Newor
reviseddefinitionslistedbelowbecomeapprovedwhentheproposedstandardisapproved.
Whenthestandardbecomeseffective,thesedefinedtermswillberemovedfromtheindividual
standardandaddedtotheGlossary.
BalancingContingencyEvent:AnysingleeventdescribedinSubsections(A),(B),or(C)below,
oranyseriesofsuchotherwisesingleevents,witheachseparatedfromthenextbylessthan
oneminute.
A. SuddenLossofgeneration:
a. Dueto
i. Unittripping,
ii. LossofgeneratorInterconnectionFacilityresultinginisolationofthe
generatorfromtheBulkElectricSystemorfromtheresponsibleentity’s
electricsystem,or
iii. SuddenunplannedoutageoftransmissionFacility;
b. And,thatcausesanunexpectedchangetotheresponsibleentity’sACE;
B. Suddenlossofanimport,duetoforcedoutageoftransmissionequipmentthatcauses
anunexpectedchangetotheresponsibleentity’sACE.
C. Suddenlossofaknownloadusedasaresourcethatcausesanunexpectedchangeto
theresponsibleentity’sACE.
MostSevereSingleContingency(MSSC):TheBalancingContingencyEvent,duetoasingle
contingency,thatwouldresultinthegreatestloss(measuredinMW)ofresourceoutputused
bytheReserveSharingGroup(RSG)oraBalancingAuthoritythatisnotparticipatingasa
memberofaRSGatthetimeoftheeventtomeetfirmsystemloadandexportobligation
(excludingexportobligationforwhichContingencyReserveobligationsarebeingmetbythe
sinkBalancingAuthority).
ReportableBalancingContingencyEvent:AnyBalancingContingencyEventresultinginaloss
ofMWoutputgreaterthanorequaltothelesseramountof80percentoftheMostSevere
SingleContingencyor500MWandoccurringwithinarollingoneͲminuteintervalbasedonEMS
scanratedata.The80%thresholdmaybereduceduponwrittennotificationtotheRegional
Entity.
ContingencyEventRecoveryPeriod:Aperiodbeginningatthetimethattheresourceoutput
beginstodeclinewithinthefirstoneͲminuteintervalthatdefinesaBalancingContingency
Event,andextendsforfifteenminutesthereafter.
ContingencyReserveRestorationPeriod:Aperiodnotexceeding90minutesfollowingtheend
oftheContingencyEventRecoveryPeriod.

BALͲ002Ͳ2
February2013



Page2of8



StandardBALͲ002Ͳ2–ContingencyReserveforRecoveryfromaBalancingContingencyEvent
PreͲReportableContingencyEventACEValue:TheaveragevalueofACEinthe16second
intervalimmediatelypriortothestartoftheContingencyEventRecoveryPeriodbasedonEMS
scanratedata.
ReserveSharingGroupReportingACE:Atanygiventimeofmeasurementfortheapplicable
ReserveSharingGroup,thealgebraicsumoftheACEs(ascalculatedatsuchtimeof
measurement)ofalloftheBalancingAuthoritiesthatmakeuptheReserveSharingGroup.


ContingencyReserve:TheprovisionofcapacitythatmaybedeployedbytheBalancing
AuthoritytorespondtoaBalancingContingencyEventandothercontingencyrequirements
(suchasEnergyEmergencyAlertsLevel2orLevel3).Thecapacitymaybeprovidedby
resourcessuchasDemandSideManagement(DSM),InterruptibleLoadandunloaded
generation.



BALͲ002Ͳ2
February2013





Page3of8



StandardBALͲ002Ͳ2–ContingencyReserveforRecoveryfromaBalancingContingencyEvent
A. Introduction
1.

Title: ContingencyReserveforRecoveryFromaBalancingContingencyEvent

2.

Number: BALͲ002Ͳ2

3.

Purpose: ToensuretheBalancingAuthorityorReserveSharingGroupbalances
resourcesanddemandandreturnstheBalancingAuthority’sorReserveSharing
Group’sAreaControlErrortodefinedvalues(subjecttoapplicablelimits)followinga
ReportableBalancingContingencyEvent.

4.

Applicability:
Applicabilityisdeterminedonanindividualeventbasis,butthisstandarddoesnot
applytoaResponsibleEntityduringperiodswhentheResponsibleEntityisinEnergy
EmergencyAlertLevel2orLevel3.
4.1. BalancingAuthority
4.1.1 ABalancingAuthoritythatisamemberofaReserveSharingGroupisthe
ResponsibleEntityonlyinperiodsduringwhichtheBalancingAuthorityis
notinactivestatusundertheapplicableagreementorgoverningrulesfor
theReserveSharingGroup.
4.2. ReserveSharingGroup

5.

(Proposed)EffectiveDate:
5.1. Firstdayofthefirstcalendarquarterthatissixmonthsbeyondthedatethat
thisstandardisapprovedbyapplicableregulatoryauthorities,orinthose
jurisdictionswhereregulatoryapprovalisnotrequired,thestandardbecomes
effectivethefirstdayofthefirstcalendarquarterthatissixmonthsbeyondthe
datethisstandardisapprovedbytheNERCBoardofTrustees’,orasotherwise
madepursuanttothelawsapplicabletosuchEROgovernmentalauthorities.

B. Requirements
R1.

ExceptwhenanEnergyEmergencyAlertLevel2orLevel3isineffect,theResponsible
EntityexperiencingaReportableBalancingContingencyEventshalldemonstratethat
withintheContingencyEventRecoveryPeriodtheResponsibleEntityreturneditsACE
to:[ViolationRiskFactor:Medium][TimeHorizon:RealͲtimeOperations]
x

BALͲ002Ͳ2
February2013

Zero,(ifitsPreͲReportableContingencyEventACEValuewaspositiveorequalto
zero):
o

lessthesumofthemagnitudesofallsubsequentBalancingContingency
EventsthatoccurwithintheContingencyEventRecoveryPeriod,and

o

Furtherreducedbythemagnitudeofthedifferencebetween(i)the
ResponsibleEntity’sMostSevereSingleContingency(MSSC)and(ii)thesum
ofthemagnitudesoftheReportableBalancingContingencyEventandall
previousBalancingContingencyEventsthathavenotcompletedtheir



Page4of8



StandardBALͲ002Ͳ2–ContingencyReserveforRecoveryfromaBalancingContingencyEvent
ContingencyEventRestorationPeriodwhenthesumreferencedinclause(ii)
ofthisbulletisgreaterthanMSSC,
Or,
x

ItsPreͲReportableContingencyEventACEValue,(ifitsPreͲReportable
ContingencyEventACEValuewasnegative),
o lessthesumofthemagnitudesofallsubsequentBalancingContingency
EventsthatoccurwithintheContingencyEventRecoveryPeriod,and
o Furtherreducedbythemagnitudeofthedifferencebetween(i)the
ResponsibleEntity’sMostSevereSingleContingency(MSSC)and(ii)thesum
ofthemagnitudesoftheReportableBalancingContingencyEventandall
previousBalancingContingencyEventsthathavenotcompletedtheir
ContingencyEventRestorationPeriodwhenthesumreferencedinclause(ii)
ofthisbulletisgreaterthanMSSC.

R2.

ExceptduringtheDisturbanceRecoveryPeriodandContingencyReserveRecovery
Period,orduringanEnergyEmergencyAlertLevel2or3,eachResponsibleEntity
shallmaintainanamountofContingencyReserveatleastequaltoitsMostSevere
SingleContingency.[ViolationRiskFactor:Medium][TimeHorizon:RealͲtime
Operations]


C. Measures
M1.

EachResponsibleEntityshallhave,andprovideuponrequest,asevidence,aCR
Form1withdateandtimeofoccurrencetoshowcompliancewithRequirementR1,
includingadditionaldocumentationonanyBalancingContingencyEventthathasnot
completeditsContingencyReserveRestorationPeriodandthatisusedtoreducethe
recoverytotheamountlimitedbyMSSC.

M2.

EachResponsibleEntityshallhavedateddocumentationthatdemonstratesits
ContingencyReserve,averagedovereachClockHour,wasmaintainedinaccordance
withtheamountsidentifiedinRequirementR2exceptwithinthefirst105minutes
followinganeventrequiringtheactivationofContingencyReserve.


D. Compliance
1.

ComplianceMonitoringProcess
1.1. ComplianceEnforcementAuthority
AsdefinedintheNERCRulesofProcedure,“ComplianceEnforcementAuthority”
meansNERCortheRegionalEntityintheirrespectiverolesofmonitoringand
enforcingcompliancewiththeNERCReliabilityStandards.

BALͲ002Ͳ2
February2013



Page5of8



StandardBALͲ002Ͳ2–ContingencyReserveforRecoveryfromaBalancingContingencyEvent
1.2. DataRetention
Thefollowingevidenceretentionperiodsidentifytheperiodoftimeanentityis
requiredtoretainspecificevidencetodemonstratecompliance.Forinstances
wheretheevidenceretentionperiodspecifiedbelowisshorterthanthetime
sincethelastaudit,theComplianceEnforcementAuthoritymayaskanentityto
provideotherevidencetoshowthatitwascompliantforthefullͲtimeperiod
sincethelastaudit.
TheResponsibleEntityshallretaindataorevidencetoshowcomplianceforthe
currentyear,plusthreepreviouscalendaryears,unlessdirectedbyits
ComplianceEnforcementAuthoritytoretainspecificevidenceforalonger
periodoftimeaspartofaninvestigation.
IfaResponsibleEntityisfoundnoncompliant,itshallkeepinformationrelatedto
thenoncomplianceuntilfoundcompliant,orforthetimeperiodspecifiedabove,
whicheverislonger.
TheComplianceEnforcementAuthorityshallkeepthelastauditrecordsandall
subsequentrequestedandsubmittedrecords.
1.3. ComplianceMonitoringandAssessmentProcesses
ComplianceAudits
SelfͲCertifications
SpotChecking
ComplianceInvestigations
SelfͲReporting
Complaints
1.4. AdditionalComplianceInformation
TheResponsibleEntitymayuseContingencyReserveforanyBalancing
ContingencyEventandasrequiredforanyotherapplicablestandards.
AResponsibleEntityisnotsubjecttocompliancewiththisstandardinanyperiod
duringwhichtheResponsibleEntityisinanEnergyEmergencyAlertLevel2or
Level3.

2.

ViolationSeverityLevels
R#
R1

BALͲ002Ͳ2
February2013

LowerVSL

ModerateVSL

HighVSL

SevereVSL

TheResponsible
Entityrecovered
froma
Reportable

TheResponsible
Entityrecovered
froma
Reportable

TheResponsible
Entityrecovered
froma
Reportable

TheResponsible
Entityrecovered
froma
Reportable



Page6of8



StandardBALͲ002Ͳ2–ContingencyReserveforRecoveryfromaBalancingContingencyEvent

R2

Balancing
Contingency
Eventduringthe
Contingency
EventRecovery
Periodbut
recoveredless
than100%but
morethan90%
ofrequired
recovery.

Balancing
Contingency
Eventduringthe
Contingency
EventRecovery
Periodbut
recovered90%or
lessbutmore
than80%of
required
recovery.

Balancing
Contingency
Eventduringthe
Contingency
EventRecovery
Periodbut
recovered80%or
lessbutmore
than70%of
required
recovery.

Balancing
Contingency
Eventduringthe
Contingency
EventRecovery
Periodbut
recovered70%or
lessofrequired
recovery.

Ineachcalendar
quarter,the
Responsible
Entityhad
Contingency
Reservesbutits
Contingency
Reservewas
deficientfor
morethan5
hoursbutless
thanorequalto
15hours.

Ineachcalendar
quarter,the
Responsible
Entityhad
Contingency
Reservesbutits
Contingency
Reservewas
deficientfor
morethan15
hoursbutless
thanorequalto
25hours.

Ineachcalendar
quarter,the
Responsible
Entityhad
Contingency
Reservesbutits
Contingency
Reservewas
deficientfor
morethan25
hoursbutless
thanorequalto
35hours.

Ineachcalendar
quarter,the
Responsible
Entityhad
Contingency
Reservesbutits
Contingency
Reservewas
deficientfor
morethan35
hours.


E. RegionalVariances
None.
F. AssociatedDocuments
BALͲ002Ͳ2ContingencyReserveforRecoveryfromaBalancingContingencyEvent
BackgroundDocument
CRForm1
VersionHistory
Version

Date

Action

ChangeTracking

0

April1,2005

EffectiveDate

New

0

August8,2005 Removed“Proposed”fromEffective
Date

Errata

0

February14,
2006

Errata

BALͲ002Ͳ2
February2013

Revisedgraphonpage3,“10min.”to
“Recoverytime.”Removedfourth


Page7of8



StandardBALͲ002Ͳ2–ContingencyReserveforRecoveryfromaBalancingContingencyEvent
bullet.
2



NERCBOTAdoption

Completerevision



















BALͲ002Ͳ2
February2013



Page8of8



StandardBALͲ002Ͳ2–ContingencyReserveforRecoveryfromaBalancingContingencyEvent
StandardDevelopmentRoadmap
Thissectionismaintainedbythedraftingteamduringthedevelopmentofthestandardandwill
beremovedwhenthestandardbecomeseffective.
DevelopmentStepsCompleted:
1. TheSARforProject2007Ͳ18,ReliabilityBasedControls,waspostedfora30Ͳdayformal
commentperiodonMay15,2007.
2. ArevisedSARforProject2007Ͳ05,ReliabilityBasedControls,waspostedforasecond
30ͲdayformalcommentperiodonSeptember10,2007.
3. TheStandardsCommitteeapprovedProject2007Ͳ18,ReliabilityBasedControls,tobe
movedtostandarddraftingonDecember11,2007.
4. TheSARforProject2007Ͳ05,BalancingAuthorityControls,waspostedfora30Ͳday
formalcommentperiodonJuly3,2007.
5. TheStandardsCommitteeapprovedProject2007Ͳ05,BalancingAuthorityControls,to
bemovedtostandarddraftingonJanuary18,2008.
6. TheStandardsCommitteeapprovedthemergerofProject2007Ͳ05,BalancingAuthority
Controls,andProject2007Ͳ18,ReliabilityͲbasedControl,asProject2010Ͳ14,Balancing
AuthorityReliabilityͲbasedControlsonJuly28,2010.
7. TheNERCStandardsCommitteeapprovedbreakingProject2010Ͳ14,Balancing
AuthorityReliabilityͲbasedControls,intotwophasesandmovingPhase1(Project2010Ͳ
14.1,BalancingAuthorityReliabilityͲbasedControls–Reserves)intoformalstandards
developmentonJuly13,2011.
8. Thedraftstandardwaspostedfor30ͲdayformalindustrycommentperiodfromJune4,
2012throughJuly3,2012

ProposedActionPlanandDescriptionofCurrentDraft:
Thisisthesecondpostingoftheproposednewstandard.Thisproposeddraftstandardwillbe
postedfora45ͲdayformalcommentperiodbeginningonMarch21,2013throughApril25,
2013.

FutureDevelopmentPlan:
AnticipatedActions
1. Secondposting

AnticipatedDate
March/April2013

2. InitialBallot

April2013

3. RecirculationBallot

October2013

4. NERCBOTadoption.

November2013

BALͲ002Ͳ2
February2013



Page1of8



StandardBALͲ002Ͳ2–ContingencyReserveforRecoveryfromaBalancingContingencyEvent


DefinitionsofTermsUsedinStandard
Thissectionincludesallnewlydefinedorrevisedtermsusedintheproposedstandard.Terms
alreadydefinedintheReliabilityStandardsGlossaryofTermsarenotrepeatedhere.Newor
reviseddefinitionslistedbelowbecomeapprovedwhentheproposedstandardisapproved.
Whenthestandardbecomeseffective,thesedefinedtermswillberemovedfromtheindividual
standardandaddedtotheGlossary.
BalancingContingencyEvent:AnysingleeventdescribedinSubsections(A),(B),or(C)below,
oranyseriesofsuchotherwisesingleevents,witheachseparatedfromthenextbylessthan
oneminute.
A. SuddenLossofgGeneration:
a. Dueto
i. Unittripping,
ii. LossofgeneratorInterconnectionFacilityiesresultinginisolationofthe
generatorfromtheBulkElectricSystemorfromtheresponsibleentity’s
electricsystem,or
iii. SuddenunplannedoutageoftransmissionFacilityies;
b. And,thatcausesanunexpectedchangetotheresponsibleentity’sACE;
c. Provided,however,thatnormal,recurringoperatingcharacteristicsofaunitdo
notconstitutesuddenorunanticipatedlossesandmaynotbesubjecttothis
definition.
B. SuddenlLossofanNonͲInterruptibleiImport:,duetoforcedoutageoftransmission
equipmentthatcausesanunexpectedchangetotheresponsibleentity’sACE.
a.B.
AsuddenlossofanonͲinterruptibleimport,duetoforcedoutageof
transmissionequipmentthatcausesanunexpectedchangetotheresponsibleentity’s
ACE.
C. Suddenlossofaknownloadusedasaresourcethatcausesanunexpectedchangeto
theresponsibleentity’sACE.UnexpectedFailureofGenerationtoMaintainorIncrease:
a. Dueto
i.
Inability to start a unit the responsible entity planned to bring online at that time
(for reasons other than lack of fuel), or
ii.
Internal plant equipment problems that force the generator to be ramped down or
taken offline;
b.C.
And that, even if not an immediate cause of an unexpected change to the
responsible entity’s ACE, will, in the responsible entity’s judgment, leave the responsible
entity unable to maintain its ACE following the failure, unless it deploys Contingency
Reserve.
MostSevereSingleContingency(MSSC):TheBalancingContingencyEvent,duetoasingle
contingency,thatwouldresultinthegreatestloss(measuredinMW)ofresourcegeneration
outputusedbytheReserveSharingGroup(RSG)oraBalancingAuthoritythatisnot
participatingasamemberofaRSGatthetimeoftheevent,orthegreatestlossofactivated
DirectControlLoadManagementusedbytheBalancingAuthority,tomeetfirmsystemload
BALͲ002Ͳ2
February2013



Page2of8



StandardBALͲ002Ͳ2–ContingencyReserveforRecoveryfromaBalancingContingencyEvent
andnonͲinterruptibleexportobligation(excludingexportobligationforwhichContingency
ReserveobligationsarebeingmetbythesinkBalancingAuthority).
ReportableBalancingContingencyEvent:AnyBalancingContingencyEventresultinginaloss
ofMWoutputgreaterthanorequaltothelesseramountof80percentoftheBalancing
Authority’sMostSevereSingleContingencyor500MWandoccurringwithinarollingoneͲ
minuteintervalbasedonEMSscanratedata.The80%thresholdmaybereduceduponwritten
notificationtotheRegionalEntity.
ContingencyEventRecoveryPeriod:Aperiodbeginningatthetimethattheresourceoutput
beginstodeclinewithinthefirstoneͲminuteintervalthatdefinesaBalancingContingency
Event,andextendsforfifteenminutesthereafternotexceeding15minutesfollowingthestart
oftheBalancingContingencyEvent.ThestartoftheBalancingContingencyEventisthepoint
intimewherethefirstchangeinMWisobservedduetotheevent.
ContingencyReserveRestorationPeriod:Aperiodnotexceeding90minutesfollowingtheend
oftheContingencyEventRecoveryPeriod,duringwhichtheamountofContingencyReserve
deployedtorecoverfromaBalancingContingencyEventistoberestored.
PreͲReportableContingencyEventACEValue:TheaveragevalueofACEinthe16second
intervalimmediatelypriortothestartoftheaReportableContingencyEventRecoveryPeriod
basedonEMSscanratedatawhentherearenopreviousReportableContingencyEventsfor
whichtheContingencyEventRecoveryPeriodisnotyetcompleted,
or
ThevalueofACEthattheBalancingAuthorityorReserveSharingGroupmustattaintofully
meetitsACErecoveryrequirementwithrespecttotheimmediatelypreviousReportable
ContingencyEventforwhichtheContingencyEventRecoveryPeriodisnotyetcompleted.
ReserveSharingGroupReportingACE:Atanygiventimeofmeasurementfortheapplicable
ReserveSharingGroup,thealgebraicsumoftheACEs(ascalculatedatsuchtimeof
measurement)ofalloftheBalancingAuthoritiesthatmakeuptheReserveSharingGroup.


ContingencyReserve:TheprovisionofcapacitythatmaybedeployedbytheBalancing
AuthoritytorespondtoaBalancingContingencyEventmeettheDisturbanceControlStandard
(DCS)andotherNERCandRegionalReliabilityOrganizationcontingencyrequirements(suchas
EnergyEmergencyAlertsLevel2orLevel3).Thecapacitymaybeprovidedbyresourcessuch
asDemandSideManagement(DSM),InterruptibleLoadandunloadedgeneration.



BALͲ002Ͳ2
February2013





Page3of8



StandardBALͲ002Ͳ2–ContingencyReserveforRecoveryfromaBalancingContingencyEvent
A. Introduction
1.

Title: ContingencyReserveforRecoveryFromaBalancingContingencyEvent

2.

Number: BALͲ002Ͳ2

3.

Purpose: ToensuretheBalancingAuthorityorReserveSharingGrouputilizesits
ContingencyReservetobalancesresourcesanddemandandreturnstheBalancing
Authority’sorReserveSharingGroup’sAreaControlErrortodefinedvalues(subject
toapplicablelimits)followingaReportableBalancingContingencyEvent.

4.

Applicability:
Applicabilityisdeterminedonanindividualeventbasis,butthisstandarddoesnot
applytoaResponsibleEntityduringperiodswhentheResponsibleEntityisinEnergy
EmergencyAlertLevel2orLevel3.
4.1. BalancingAuthority
4.1.1 ABalancingAuthoritythatisamemberofaReserveSharingGroupisthe
ResponsibleEntityonlyinperiodsduringwhichtheBalancingAuthorityis
notinactivestatusundertheapplicableagreementorgoverningrulesfor
theReserveSharingGroup.
4.2. ReserveSharingGroup

5.

(Proposed)EffectiveDate:
5.1. Firstdayofthefirstcalendarquarterthatissixmonthsbeyondthedatethat
thisstandardisapprovedbyapplicableregulatoryauthorities,orinthose
jurisdictionswhereregulatoryapprovalisnotrequired,thestandardbecomes
effectivethefirstdayofthefirstcalendarquarterthatissixmonthsbeyondthe
datethisstandardisapprovedbytheNERCBoardofTrustees’,orasotherwise
madepursuanttothelawsapplicabletosuchEROgovernmentalauthorities.

B. Requirements
R1.

ExceptwhenanEnergyEmergencyAlertLevel2orLevel3isineffect,theResponsible
EntityEachBalancingAuthorityorReserveSharingGroupexperiencingaReportable
BalancingContingencyEventshallimplementitsContingencyReserveplansothatthe
BalancingAuthorityorReserveSharingGroupcandemonstratethatwithinthe
ContingencyEventRecoveryPeriodtheResponsibleEntityreturneditsACEto,within
theContingencyEventRecoveryPeriod:[ViolationRiskFactor:Medium][Time
Horizon:RealͲtimeOperations]
x

Zero,(ifitsPreͲReportableContingencyEventACEValuewaspositiveorequalto
zero)TheBalancingAuthorityorReserveSharingGroupreturneditsACEto:
o

BALͲ002Ͳ2
February2013

Zero,lessthesumofthemagnitudesofallsubsequentBalancing
ContingencyEventsthatoccurwithintheContingencyEventRecovery
Period,andifitsACEjustpriortotheReportableContingencyEventwas
positiveorequaltozero,Or


Page4of8



StandardBALͲ002Ͳ2–ContingencyReserveforRecoveryfromaBalancingContingencyEvent
o

FurtherreducedbytheItsPreͲReportableContingencyEventACEValue,less
thesumofthemagnitudesofthedifferencebetween(i)theResponsible
Entity’sMostSevereSingleContingency(MSSC)and(ii)thesumofthe
magnitudesoftheReportableallsubsequentBalancingContingencyEvents
andallpreviousBalancingContingencyEventsthathavenotcompleted
theirthatoccurwithintheContingencyEventRestorationRecoveryPeriod
whenthesumreferencedinclause(ii)ofthisbulletisgreaterthanMSSC,,if
itsACEjustpriortotheReportableContingencyEventwasnegative.

Or,
x

ItsPreͲReportableContingencyEventACEValue,(ifitsPreͲReportable
ContingencyEventACEValuewasnegative),
o lessthesumofthemagnitudesofallsubsequentBalancingContingency
EventsthatoccurwithintheContingencyEventRecoveryPeriod,and
o Furtherreducedbythemagnitudeofthedifferencebetween(i)the
ResponsibleEntity’sMostSevereSingleContingency(MSSC)and(ii)thesum
ofthemagnitudesoftheReportableBalancingContingencyEventandall
previousBalancingContingencyEventsthathavenotcompletedtheir
ContingencyEventRestorationPeriodwhenthesumreferencedinclause(ii)
ofthisbulletisgreaterthanMSSC.Provided,however,thatineitherofthe
foregoingcases,iftheReportableContingencyEvent(individuallyorwhen
combinedwithanypreviousBalancingContingencyEventsthathavenot
completedtheirContingencyReserveRestorationPeriods)exceededthe
BalancingAuthority’sorReserveSharingGroup’sMostSevereSingle
Contingency(MSSC),thentheBalancingAuthorityorReserveSharingGroup
needonlydemonstrateACErecoveryofatleastequaltoitsMSSC,lessthe
sumofthemagnitudesofallPreviousBalancingContingencyEventsthat
havenotcompletedtheirContingencyReserveRestorationPeriods.

R2.

ExceptduringtheDisturbanceRecoveryPeriodandContingencyReserveRecovery
Period,orduringanEnergyEmergencyAlertLevel2or3,eachResponsibleEntity
shallmaintainanamountofContingencyReserveatleastequaltoitsMostSevere
SingleContingency.[ViolationRiskFactor:Medium][TimeHorizon:RealͲtime
Operations]


C. Measures
M1.

EachResponsibleEntityshallhave,andprovideuponrequest,asevidence,aCR
Form1withdateandtimeofoccurrencetoshowcompliancewithRequirementR1,
includingadditionaldocumentationonanyBalancingContingencyEventthathasnot
completeditsContingencyReserveRestorationPeriodandthatisusedtoreducethe
recoverytotheamountlimitedbyMSSC.EachBalancingAuthorityorReserve
SharingGroupshallhave,andprovideuponrequest,evidence;suchascomputer

BALͲ002Ͳ2
February2013



Page5of8



StandardBALͲ002Ͳ2–ContingencyReserveforRecoveryfromaBalancingContingencyEvent
logsoroperatorlogs,withdateandtimeofoccurrencetoshowcompliancewith
RequirementR1.
M2.

EachResponsibleEntityshallhavedateddocumentationthatdemonstratesits
ContingencyReserve,averagedovereachClockHour,wasmaintainedinaccordance
withtheamountsidentifiedinRequirementR2exceptwithinthefirst105minutes
followinganeventrequiringtheactivationofContingencyReserve.


D. Compliance
1.

ComplianceMonitoringProcess
1.1. ComplianceEnforcementAuthority
TheAsdefinedintheNERCRulesofProcedure,“ComplianceEnforcement
Authority”meansNERCortheRegionalEntityintheirrespectiverolesof
monitoringandenforcingcompliancewiththeNERCReliability
Standards.regionalentityistheComplianceEnforcementAuthority,except
wheretheresponsibleentityworksfortheregionalentity.Wherethe
responsibleentityworksfortheregionalentity,theregionalentitywillestablish
anagreementwiththeERO,oranotherentityapprovedbytheEROandFERC
(i.e.,anotherregionalentity),toberesponsibleforcomplianceenforcement.
1.2. DataRetention
Thefollowingevidenceretentionperiodsidentifytheperiodoftimeanentityis
requiredtoretainspecificevidencetodemonstratecompliance.Forinstances
wheretheevidenceretentionperiodspecifiedbelowisshorterthanthetime
sincethelastaudit,theComplianceEnforcementAuthoritymayaskanentityto
provideotherevidencetoshowthatitwascompliantforthefullͲtimeperiod
sincethelastaudit.
TheResponsibleEntityBalancingAuthorityorReserveSharingGroupshallretain
dataorevidencetoshowcomplianceforthecurrentyear,plusthreeprevious
calendaryears,unlessdirectedbyitsComplianceEnforcementAuthorityto
retainspecificevidenceforalongerperiodoftimeaspartofaninvestigation.
IfaResponsibleEntityBalancingAuthorityorReserveSharingGroupisfound
noncompliant,itshallkeepinformationrelatedtothenoncomplianceuntil
foundcompliant,orforthetimeperiodspecifiedabove,whicheverislonger.
TheComplianceEnforcementAuthorityshallkeepthelastauditrecordsandall
subsequentrequestedandsubmittedrecords.
1.3. ComplianceMonitoringandAssessmentProcesses
ComplianceAudits
SelfͲCertifications

BALͲ002Ͳ2
February2013



Page6of8



StandardBALͲ002Ͳ2–ContingencyReserveforRecoveryfromaBalancingContingencyEvent
SpotChecking
ComplianceInvestigations
SelfͲReporting
Complaints
1.4. AdditionalComplianceInformation
ABalancingAuthoritymayelecttofulfillitsContingencyReserveobligationsby
participatingasamemberofaReserveSharingGroup.
TheResponsibleEntityABalancingAuthorityorReserveSharingGroupmayuse
ContingencyReserveforanyBalancingContingencyEventandasrequiredfor
anyotherapplicablestandards.
ABalancingAuthorityorReserveSharingGroupmayoptionallyreducethe80
percentthreshold,uponwrittennotificationtotheRegionalEntity.AResponsible
Entityisnotsubjecttocompliancewiththisstandardinanyperiodduringwhich
theResponsibleEntityisinanEnergyEmergencyAlertLevel2orLevel3.

2.

ViolationSeverityLevels
R#

LowerVSL

ModerateVSL

HighVSL

SevereVSL

R1

TheResponsible
Entityrecovered
froma
Reportable
Balancing
Contingency
Eventduringthe
Contingency
EventRecovery
Periodbut
recoveredless
than100%but
morethan90%
ofrequired
recovery.

TheResponsible
Entityrecovered
froma
Reportable
Balancing
Contingency
Eventduringthe
Contingency
EventRecovery
Periodbut
recovered90%or
lessbutmore
than80%of
required
recovery.

TheResponsible
Entityrecovered
froma
Reportable
Balancing
Contingency
Eventduringthe
Contingency
EventRecovery
Periodbut
recovered80%or
lessbutmore
than70%of
required
recovery.

TheResponsible
Entityrecovered
froma
Reportable
Balancing
Contingency
Eventduringthe
Contingency
EventRecovery
Periodbut
recovered70%or
lessofrequired
recovery.

R2

Ineachcalendar
quarter,the
Responsible
Entityhad
Contingency
Reservesbutits

Ineachcalendar
quarter,the
Responsible
Entityhad
Contingency
Reservesbutits

Ineachcalendar
quarter,the
Responsible
Entityhad
Contingency
Reservesbutits

Ineachcalendar
quarter,the
Responsible
Entityhad
Contingency
Reservesbutits

BALͲ002Ͳ2
February2013



Page7of8



StandardBALͲ002Ͳ2–ContingencyReserveforRecoveryfromaBalancingContingencyEvent
Contingency
Reservewas
deficientfor
morethan5
hoursbutless
thanorequalto
15hours.

Contingency
Reservewas
deficientfor
morethan15
hoursbutless
thanorequalto
25hours.

Contingency
Reservewas
deficientfor
morethan25
hoursbutless
thanorequalto
35hours.

Contingency
Reservewas
deficientfor
morethan35
hours.


E. RegionalVariances
None.
F. AssociatedDocuments
BALͲ002Ͳ2ContingencyReserveforRecoveryfromaBalancingContingencyEvent
BackgroundDocument
CRForm1
VersionHistory
Version

Date

Action

ChangeTracking

0

April1,2005

EffectiveDate

New

0

August8,2005 Removed“Proposed”fromEffective
Date

Errata

0

February14,
2006

Revisedgraphonpage3,“10min.”to
“Recoverytime.”Removedfourth
bullet.

Errata

2



NERCBOTAdoption

Completerevision



















BALͲ002Ͳ2
February2013



Page8of8



Implementation Plan

Project 2010-14.1 Balancing Authority Reliability-based Controls
- Reserves
ImplementationPlanforBALͲ002Ͳ2–ContingencyReserveforRecoveryfromaBalancing
ContingencyEvent

ApprovalsRequired
BALͲ002Ͳ2–ContingencyReserveforRecoveryfromaBalancingContingencyEvent

PrerequisiteApprovals
None

RevisionstoGlossaryTerms
ThefollowingdefinitionsshallbecomeeffectivewhenBALͲ002Ͳ2becomeseffective:

BalancingContingencyEvent:AnysingleeventdescribedinSubsections(A),(B),or(C)below,or
anyseriesofsuchotherwisesingleevents,witheachseparatedfromthenextbylessthanone
minute.
A. SuddenLossofgeneration:
a. Dueto
i. Unittripping,
ii. LossofgeneratorInterconnectionFacilityresultinginisolationofthe
generatorfromtheBulkElectricSystemorfromtheresponsibleentity’s
electricsystem,or
iii. SuddenunplannedoutageoftransmissionFacilities;
b. And,thatcausesanunexpectedchangetotheresponsibleentity’sACE;
B. SuddenlossofanImport duetoforcedoutageoftransmissionequipmentthatcausesan
unexpectedchangetotheresponsibleentity’sACE.
C. Suddenlossofaknownloadusedasaresourcethatcausesanunexpectedchangetothe
responsibleentity’sACE.
MostSevereSingleContingency(MSSC):TheBalancingContingencyEvent,duetoasingle
contingency,thatwouldresultinthegreatestloss(measuredinMW)ofresourceoutputusedby

theReserveSharingGroup(RSG)oraBalancingAuthoritythatisnotparticipatingasamemberofa
RSGatthetimeoftheeventtomeetfirmsystemloadandexportobligation(excludingexport
obligationforwhichContingencyReserveobligationsarebeingmetbythesinkBalancing
Authority).
ReportableBalancingContingencyEvent:AnyBalancingContingencyEventresultinginalossof
MWoutputgreaterthanorequaltothelesseramountof80percentoftheMostSevereSingle
Contingency,or500MWandoccurringwithinarollingoneͲminuteintervalbasedonEMSscanrate
data.
ContingencyEventRecoveryPeriod:Aperiodbeginningatthetimethattheresourceoutput
beginstodeclinewithinthefirstoneͲminuteintervalthatdefinesaBalancingContingencyEvent,
andextendsforfifteenminutesthereafter.
ContingencyReserveRestorationPeriod:Aperiodnotexceeding90minutesfollowingtheendof
theContingencyEventRecoveryPeriod.

PreͲReportableContingencyEventACEValue:TheaveragevalueofACEinthe16secondinterval
immediatelypriortothestartoftheContingencyEventRecoveryPeriodbasedonEMSscanrate
data.

ReserveSharingGroupReportingACE:Atanygiventimeofmeasurementfortheapplicable
ReserveSharingGroup,thealgebraicsumoftheACEs(ascalculatedatsuchtimeofmeasurement)
ofalloftheBalancingAuthoritiesthatmakeuptheReserveSharingGroup.

ContingencyReserve:TheprovisionofcapacitythatmaybedeployedbytheBalancingAuthorityto
respondtoaBalancingContingencyEventandotherNERCcontingencyrequirements(suchas
EnergyEmergencyAlertsLevel2orLevel3).Thecapacitymaybeprovidedbyresourcessuchas
DemandSideManagement(DSM),InterruptibleLoadandunloadedgeneration..


ApplicableEntities
BalancingAuthority
ReserveSharingGroup

ApplicableFacilities
N/A

ConformingChangestoOtherStandards

BALͲ002Ͳ2–ContingencyReserveforRecoveryfromaBalancingContingencyEvent
February2013

2

None

EffectiveDates
BALͲ002Ͳ2shallbecomeeffectiveasfollows:
Firstdayofthefirstcalendarquarterthatissixmonthsbeyondthedatethatthisstandardis
approved by applicable regulatory authorities, or in those jurisdictions where regulatory
approval is not required, the standard becomes effective the first day of the first calendar
quarter that is six months beyond the date this standard is approved by the NERC Board of
Trustees’, or as otherwise made pursuant to the laws applicable to such ERO governmental
authorities.

Justification
ThesixͲmonthperiodforimplementationofBALͲ002Ͳ2willprovideampletimeforBalancing
Authoritiestomakenecessarymodificationstoexistingsoftwareprogramstoensurecompliance.

Retirements
BALͲ002Ͳ0,DisturbanceControlPerformance,andBALͲ002Ͳ1,DisturbanceControlPerformanceshould
beretiredatmidnightofthedayimmediatelypriortotheEffectiveDateofBALͲ002Ͳ2intheparticular
jurisdictioninwhichthenewstandardisbecomingeffective.


BALͲ002Ͳ2–ContingencyReserveforRecoveryfromaBalancingContingencyEvent
February2013

3

Implementation Plan

Project 2010-14.1 Balancing Authority Reliability-based Controls
- Reserves
ImplementationPlanforBALͲ002Ͳ2–ContingencyReserveforRecoveryfromaBalancing
ContingencyEvent

ApprovalsRequired
BALͲ002Ͳ2–ContingencyReserveforRecoveryfromaBalancingContingencyEvent

PrerequisiteApprovals
None

RevisionstoGlossaryTerms
ThefollowingdefinitionsshallbecomeeffectivewhenBALͲ002Ͳ2becomeseffective:

BalancingContingencyEvent:AnysingleeventdescribedinSubsections(A),(B),or(C)below,or
anyseriesofsuchotherwisesingleevents,witheachseparatedfromthenextbylessthanone
minute.
A. SuddenLossofgGeneration:
a. Dueto
i. Uunittripping,
ii. LlossofgeneratorInterconnectionFacilityiesresultinginisolationofthe
generatorfromtheBulkElectricSystemorfromtheresponsibleentity’s
electricsystem,or
iii. SsuddenunplannedoutageoftransmissionFacilities;
b. And,thatcausesanunexpectedchangetotheresponsibleentity’sACE;
c. Provided,however,thatnormal,recurringoperatingcharacteristicsofaunitdonot
constitutesuddenorunanticipatedlossesandmaynotbesubjecttothisdefinition.
B. SuddenlLossofanNonͲInterruptibleImport duetoforcedoutageoftransmission
equipmentthatcausesanunexpectedchangetotheresponsibleentity’sACE.:
a. AsuddenlossofanonͲinterruptibleimport,duetoforcedoutageoftransmission
equipment,thatcausesanunexpectedchangetotheresponsibleentity’sACE.

C. Suddenlossofaknownloadusedasaresourcethatcausesanunexpectedchangetothe
responsibleentity’sACE.UnexpectedFailureofGenerationtoMaintainorIncrease:
a. Dueto
i.
Inability to start a unit the responsible entity planned to bring online at that time (for
reasons other than lack of fuel), or
ii.
Internal plant equipment problems that force the generator to be ramped down or taken
offline;
b.C. And that, even if not an immediate cause of an unexpected change to the responsible
entity’s ACE, will, in the responsible entity’s judgment, leave the responsible entity unable
to maintain its ACE following the failure unless it deploys Contingency Reserve.
MostSevereSingleContingency(MSSC):TheBalancingContingencyEvent,duetoasingle
contingency,thatwouldresultinthegreatestloss(measuredinMW)ofresourcegenerationoutput
usedbytheReserveSharingGroup(RSG)oraBalancingAuthoritythatisnotparticipatingasa
memberofaRSGatthetimeoftheevent,orthegreatestlossofactivatedDirectControlLoad
ManagementusedbytheBalancingAuthoritytomeetfirmsSystemlLoadandnonͲinterruptible
exportobligation(excludingexportobligationforwhichContingencyReserveobligationsarebeing
metbythesinkBalancingAuthority).
ReportableBalancingContingencyEvent:AnyBalancingContingencyEventresultinginalossof
MWoutputgreaterthanorequaltothelesseramountof80percentoftheBalancingAuthority’s
MostSevereSingleContingency,or500MWandoccurringwithinarollingoneͲminuteinterval
basedonEMSscanratedata.
ContingencyEventRecoveryPeriod:Aperiodbeginningatthetimethattheresourceoutput
beginstodeclinewithinthefirstoneͲminuteintervalthatdefinesaBalancingContingencyEvent,
andextendsforfifteenminutesthereafternotexceeding15minutesfollowingthestartofthe
BalancingContingencyEvent.ThestartoftheBalancingContingencyEventisthepointintime
wherethefirstchangeinMWisobservedduetotheevent.
ContingencyReserveRestorationPeriod:Aperiodnotexceeding90minutesfollowingtheendof
theContingencyEventRecoveryPeriod,duringwhichtheamountofContingencyReserve
deployedtorecoverfromaBalancingContingencyEventistoberestored.

PreͲReportableContingencyEventACEValue:TheaveragevalueofACEinthe16secondinterval
immediatelypriortothestartoftheaReportableContingencyEventRecoveryPeriodbasedon
EMSscanratedatawhentherearenopreviousReportableContingencyEventsforwhichthe
ContingencyEventRecoveryPeriodisnotyetcompleted,
or
ThevalueofACEthattheBalancingAuthorityorReserveSharingGroupmustattaintofullymeet
itsACErecoveryrequirementwithrespecttotheimmediatelypreviousReportableContingency
EventforwhichtheContingencyEventRecoveryPeriodisnotyetcompleted.


BALͲ002Ͳ2–ContingencyReserveforRecoveryfromaBalancingContingencyEvent
February2013

2

ReserveSharingGroupReportingACE:Atanygiventimeofmeasurementfortheapplicable
ReserveSharingGroup,thealgebraicsumoftheACEs(ascalculatedatsuchtimeofmeasurement)
ofalloftheBalancingAuthoritiesthatmakeuptheReserveSharingGroup.

ContingencyReserve:TheprovisionofcapacitythatmaybedeployedbytheBalancingAuthorityto
respondtoaBalancingContingencyEventmeettheDisturbanceControlStandard(DCS)andother
NERCandRegionalReliabilityOrganizationcontingencyrequirements(suchasEnergyEmergency
AlertsLevel2orLevel3).ThecapacitymaybeprovidedbyresourcessuchasDemandSide
Management(DSM),InterruptibleLoadandunloadedgeneration..


ApplicableEntities
BalancingAuthority
ReserveSharingGroup

ApplicableFacilities
N/A

ConformingChangestoOtherStandards
None

EffectiveDates
BALͲ002Ͳ2shallbecomeeffectiveasfollows:
Firstdayofthefirstcalendarquarterthatissixmonthsbeyondthedatethatthisstandardis
approved by applicable regulatory authorities, or in those jurisdictions where regulatory
approval is not required, the standard becomes effective the first day of the first calendar
quarter that is six months beyond the date this standard is approved by the NERC Board of
Trustees’, or as otherwise made pursuant to the laws applicable to such ERO governmental
authorities.

Justification
ThesixͲmonthperiodforimplementationofBALͲ002Ͳ2willprovideampletimeforBalancing
Authoritiestomakenecessarymodificationstoexistingsoftwareprogramstoensurecompliance.

Retirements

BALͲ002Ͳ2–ContingencyReserveforRecoveryfromaBalancingContingencyEvent
February2013

3

BALͲ002Ͳ0,DisturbanceControlPerformance,andBALͲ002Ͳ1,DisturbanceControlPerformanceshould
beretiredatmidnightofthedayimmediatelypriortotheEffectiveDateofBALͲ002Ͳ2intheparticular
jurisdictioninwhichthenewstandardisbecomingeffective.


BALͲ002Ͳ2–ContingencyReserveforRecoveryfromaBalancingContingencyEvent
February2013

4

Unofficial Comment Form

Project 2010-14.1 Balancing Authority Reliability-based Control
BAL-001-2 í Real Power Balancing Control Performance
Please do not use this form to submit comments on the proposed revisions to BAL-001-2 Real Power
Balancing Control Performance. Comments must be submitted on the electronic comment form by 8
p.m. ET on April 25, 2013.
If you have questions please contact Darrel Richardson (via email) or by telephone at (609) 613-1848.
Background Information:

Control Performance Standard 1 (CPS1) has been retained, and details for calculating CPS1 are included
in Attachment 1. Calculation of Reporting Area Control Error (Reporting ACE) has been clarified, and
details for calculating Reporting ACE are also included in Attachment 1. The Balancing Authority ACE
Limit (BAAL), an interconnection frequency and Balancing Authority ACE measurement, is included in
this standard as Requirement 2 and replaces Control Performance Standard 2 (CPS2). Details for the
calculation of BAAL are included in Attachment 2.
CPS2 was not designed to address Interconnection frequency. Currently, it measures the ability of a
Balancing Authority to maintain its average ACE within a fixed limit of plus or minus a MW value called
L10. To be compliant, a Balancing Authority must demonstrate its average ACE value during a
consecutive ten minute period was within the L10 bound 90 percent of all 10 minute periods over a
one month period. While this standard does require the Balancing Authority to correct its ACE to not
exceed specific bounds, it fails to recognize Interconnection frequency.
BAAL is defined by two equations, BAAL low and BAAL high. BAAL low is for Interconnection frequency
values less than 60 hertz and BAAL high is for Interconnection frequency values greater than 60 hertz.
BAAL values for each Balancing Authority are dynamic and change as Interconnection frequency
changes. For example, as Interconnection frequency moves from 60 hertz, the ACE limit for each
Balancing Authority becomes more restrictive. The BAAL provides each Balancing Authority a dynamic
ACE limit that is a function of Interconnection frequency.

As a proof of concept for the proposed BAAL standard, a BAAL field trial was approved by the NERC
Standards Committee and the Operating Committee. Currently there are 13 Balancing Authorities
participating in the Eastern Interconnection, 26 Balancing Authorities participating in the Western
Interconnection, the ERCOT Balancing Authority, and Quebec. Reliability Coordinators for all
interconnections continue to monitor the performance of those participating Balancing Authorities and
provide information to support monthly analysis of the BAAL field trial. As of the end of September
2011, no reliability issues with the BAAL field trial have been identified by any Reliability Coordinator.
Questions

You do not have to answer all questions. Enter all comments in plain text format. Bullets, numbers,
and special formatting will not be retained. Insert a “check” mark in the appropriate boxes by doubleclicking the gray areas.
1. The BARC SDT has developed two new terms to be used with this standard.
Regulation Reserve Sharing Group
A group whose members consist of two or more Balancing Authorities that collectively
maintain, allocate, and supply the regulating reserve required for all member Balancing
Authorities to use in meeting applicable regulating standards.
Regulation Reserve Sharing Group Reporting ACE
At any given time of measurement for the applicable Regulation Reserve Sharing Group,
the algebraic sum of the Reporting ACEs (as calculated at such time of measurement) of
the Balancing Authorities participating in the Regulation Reserve Sharing Group at the
time of measurement.
Do you agree with the proposed definitions in this standard? If not, please explain in the
comment area below.
Yes
No
Comments:
2. If you are not in support of this draft standard, what modifications do you believe need to be
made in order for you to support the standard? Please list the issues and your proposed solution
to them.
Comments:
3. If you have any other comments on BAL-001-2 that you haven’t already mentioned above, please
provide them here:
Comments:

Unofficial Comment Form
BAL-001-2 Real Power Balancing Control Performance

2

Unofficial Comment Form

Project 2010-14.1 Balancing Authority Reliability-based Control
BAL-002-íContingency Reserve for Recovery from a Balancing
Contingency Event
Please do not use this form to submit comments on the proposed revisions to BAL-002-2 Contingency
Reserve for Recovery from a Balancing Contingency Event. Comments must be submitted on the
electronic comment form by 8 p.m. ET on April 25, 2013.
If you have questions please contact Darrel Richardson (via email) or by telephone at (609) 613-1848.
Background Information:

Since loss of generation occurrences so often impacts all Balancing Authorities throughout an
Interconnection, BAL-002 was created to specify recovery actions and time frames. The original
Standards Authorization Request (SAR) approved by the Industry presumes there is presently sufficient
contingency reserve in all the North American Interconnections. The underlying goal of the SAR was to
update the Standard to make the measurement process more objective and to provide information to
the Balancing Authority or Reserve Sharing Group such that the parties would better understand the
use of contingency reserve to balance resources and demand following a Reportable Contingency
Event. The primary objective of BAL-002-2 is to measure the success of recovering from contingency
events.
Questions

You do not have to answer all questions. Enter all comments in plain text format. Bullets, numbers,
and special formatting will not be retained. Insert a “check” mark in the appropriate boxes by doubleclicking the gray areas.
1. The BARC SDT has modified the definition for Balancing Contingency Event based on comments
received from the industry. Do you agree that the modifications provide addition clarity? If not,
please explain in the comment area below.
Yes
No
Comments:
2. The BARC SDT has modified the current definition for Contingency Reserve. Do you agree that
the modified definition provides for greater clarity? If not, please explain in the comment area
below.

Yes
No
Comments:
3. The BARC SDT has created a definition for Reserve Sharing Group Reporting ACE. Do you agree
with this definition? If not, please explain in the comment area below.
Yes
No
Comments:
4. The BARC SDT has added language to the proposed requirements in the standard and to the
definition for Contingency Reserve to resolve any conflicts between this standard and the EOP
standards. Do you agree that this modification was necessary and that any possible issues are
now resolved? If not, please explain in the comment area.
Yes
No
Comments:
5. The BARC SDT has developed Requirement R2 which requires entities to have Contingency
Reserve at least equal to its MSSC. This requirement was added to address, in conjunction with
Requirement R1, the FERC Directive for a continent wide Contingency Reserve policy. Do you
agree that this addresses the FERC Directive? If not, please explain in the comment area.
Yes
No
Comments:
6. The BARC SDT has assigned both Requirement R1 and Requirement R2 a “medium” VRF. Do you
agree with the proposed VRF? If not, please explain in the comment area below.
Yes
No
Comments:
7. The BARC SDT has assigned both Requirement R1 and Requirement R2 a Time Horizon of “Realtime Operations”. Do you agree with the Time Horizon the SDT has chosen? If not, please
explain in the comment area below.

Unofficial Comment Form
BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event

2

Yes
No
Comments:
8. The BARC SDT has developed VSLs for Requirement R1 and Requirement R2. Do you agree with
the VSLs in this standard? If not, please explain in the comment area.
Yes
No
Comments:
9. The BARC SDT has made significant modifications to the Background Document based on
industry comments received. Do you agree that these modifications provide additional clarity as
to the development of this standard? If not, please explain in the comment area.
Yes
No
Comments:
10. If you are not in support of this draft standard, what modifications do you believe need to be
made in order for you to support the standard? Please list the issues and your proposed solution
to the issue.
Comments:

Unofficial Comment Form
BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event

3

BAL-001-2 – Real Power
Balancing Control
Performance Standard
Background Document
February 2013





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Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Table of Contents

Table of Contents
TableofContents............................................................................................................................2
Introduction....................................................................................................................................3
BackgroundandRationalebyRequirement...................................................................................4
Requirement1............................................................................................................................4
Requirement2............................................................................................................................5

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Introduction
Thisdocumentprovidesbackgroundonthedevelopment,testing,andimplementationofBALͲ
001Ͳ2ͲRealPowerBalancingControlStandard.Theintentistoexplaintherationaleand
considerationsfortherequirementsandtheirassociatedcomplianceinformation.
TheoriginalworkforthisstandardwasdonebytheBalancingAuthorityControlsstandard
draftingteam,whichlaterjoinedwiththeReliabilityͲbasedControlStandarddraftingteam.
ThesecombinedteamswererenamedBalanceAuthorityReliabilityͲbasedControlstandard
draftingteam(BARCSDT).
ThepurposeofproposedStandardBALͲ001Ͳ2istomaintainInterconnectionfrequencywithin
predefinedfrequencylimits.ThisdraftstandarddefinesBalancingAuthorityACELimit(BAAL),
andrequiredtheBalancingAuthority(BA)tobalanceitsresourcesanddemandinRealͲtimeso
thatitsclockͲminuteaverageofitsAreaControlError(ACE)doesnotexceeditsBAALformore
than30consecutiveclockͲminutes.
AsaproofofconceptfortheproposedBAALstandard,aBAALfieldtrialwasapprovedbythe
NERCStandardsCommitteeandtheOperatingCommittee.Currentlyparticipatinginthefield
trialare13BalancingAuthoritiesintheEasternInterconnection,26BalancingAuthoritiesinthe
WesternInterconnection,theERCOTBalancingAuthority,andQuebec.ReliabilityCoordinators
forallInterconnectionscontinuetomonitortheperformanceofthoseparticipatingBalancing
AuthoritiesandprovideinformationtosupportmonthlyanalysisoftheBAALfieldtrial.Asof
theendofSeptember2011,noreliabilityissueswiththeBAALfieldtrialhavebeenidentifiedby
anyReliabilityCoordinator.TheWesternInterconnectionhasexperiencedchangesduringthe
fieldtrialwithpotentialdegradationtotransmission;however,noexplicitlinkagehasbeen
determinedbetweenthefieldtrialandthesedegradations.Forfurtherinformationonthe
resultsoftheWesternInterconnection,pleaserefertotheWECCReliabilityͲbasedControlField
TrialReport.
HistoricalSignificance
A1ͲA2ControlPerformancePolicywasimplementedin1973as:
x
x
x

A1requiredtheBalancingAuthority’sACEtoreturntozerowithin10minutesofprevious
zero.
A2requiredthattheBalancingAuthority’saveragedACEforeach10Ͳminuteperiodmustbe
withinlimits.
A1ͲA2hadthreemainshortcomings:
ƒ Lackoftheoreticaljustification
ƒ LargeACEtreatedthesameasasmallACE,regardlessofdirection
ƒ IndependentofInterconnectionfrequency

In1996,anewNERCpolicywasapprovedwhichusedCPS1,CPS2,andDCS.
CPS1isa:
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RealPowerBalancingControlPerformanceStandardBackgroundDocument
x
x
x

StatisticalmeasureofACEvariability
MeasureofACEincombinationwiththeInterconnection’sfrequencyerror
BasedonanequationderivedfromfrequencyͲbasedstatisticaltheory
CPS2is:
x
x

DesignedtolimitaControlArea’s(nowknownasaBalancingAuthority)
unscheduledpowerflows
SimilartotheoldA2criteria

TheproposedBALͲ001Ͳ2retainsCPS1,butproposesanewmeasureBAALtoreplaceCPS2.
CurrentlyCPS2:

x Doesnothaveafrequencycomponent.
x CPS2manytimesgivetheBalancingAuthoritytheindicationtomovetheirACE
oppositetowhatwillhelpfrequency.
x OnlyrequiresBalancingAuthoritiestocomply90percentofthetimeasaminimum.

Background and Rationale by Requirement
Requirement1
R1.TheResponsibleEntityshalloperatesuchthattheControlPerformanceStandard1
(CPS1),calculatedinaccordancewithAttachment1,isgreaterthanorequalto100
percentfortheapplicableInterconnectioninwhichitoperatesforeach12Ͳmonth
period,evaluatedmonthly.
BackgroundandRationale
RequirementR1isnotanewrequirement.ItisarestatementofthecurrentBALͲ001Ͳ0.1a
RequirementR1withitsequationandexplanationofitsindividualcomponentsmovedtoan
attachment,Attachment1ͲEquationsSupportingRequirementR1andMeasureM1.This
requirementiscommonlyreferredtoasControlPerformanceStandard1(CPS1).R1isintended
tomeasurehowwellaBalancingAuthorityisabletocontrolitsgenerationandload
managementprograms,asmeasuredbyitsAreaControlError(ACE),tosupportits
Interconnection’sfrequencyoverarollingoneͲyearperiod.
CPS1isameasureofaBalancingAuthority’scontrolperformanceasitrelatestoitsgeneration,
Loadmanagement,andInterconnectionfrequencywhenmeasuredinoneͲminuteaverages
overarollingoneͲyearperiod.IfallBalancingAuthoritiesonanInterconnectionarecompliant
withtheCPS1measure,thentheInterconnectionwillhavearootmeansquare(RMS)
frequencyerrorlessthantheInterconnection’sEpsilon1.
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RealPowerBalancingControlPerformanceStandardBackgroundDocument
ABalancingAuthorityreportsitsCPS1valuetoitsregionalentityeachmonth.Thismonthly
valueprovidestrendingdatatotheBalancingAuthority,NERCresourcessubcommittee,and
othersasneededtodetectchangesthatmayindicatepoorcontrolonbehalfoftheBalancing
Authority.RequirementR1remainsunchanged,althoughthewordingoftherequirementwas
modifiedtoprovideclarity.
Requirement2
R2.EachBalancingAuthorityshalloperatesuchthatitsclockͲminuteaverageofReporting
ACEdoesnotexceeditsclockͲminuteBalancingAuthorityACELimit(BAAL)formore
than30consecutiveclockͲminutes,ascalculatedinAttachment2,fortheapplicable
InterconnectioninwhichtheBalancingAuthorityoperates.
BackgroundandRationale
RequirementR2isanewrequirementintendedtoreplaceexistingBALͲ001Ͳ0.1aRequirement
R2,commonlyreferredtoasControlPerformanceStandard2(CPS2).Theproposed
RequirementR2isintendedtoenhancethereliabilityofeachInterconnectionbymaintaining
frequencywithinpredefinedlimitsunderallconditions.

TheBalancingAuthorityACELimits(BAAL)areuniqueforeachBalancingAuthorityandprovide
dynamiclimitsforitsAreaControlError(ACE)valuelimitasafunctionofitsInterconnection
frequency.BAALwasderivedbasedonreliabilitystudiesandanalysiswhichdefineda
FrequencyTriggerLimit(FTL)boundmeasuredinHz.TheFTLisequaltoScheduledFrequency,
plusorminusthreetimesanInterconnection’sEpsilon1value.Epsilon1istherootmean
square(RMS)targetedfrequencyerrorforeachInterconnection,asrecommendedbytheNERC
ResourcesSubcommitteeandapprovedbytheNERCOperatingCommittee.Epsilon1values
foreachInterconnectionareunique.WhenaBalancingAuthorityexceedsitsBAAL,itis
providingmorethanitsshareofriskthattheInterconnectionwillexceeditsFTL.Whenall
BalancingAuthoritiesarewithintheirBAAL(highandlow),theInterconnectionfrequencywill
bewithinitsFTLlimits.

BAALisdefinedbytwoequations;BAALlowandBAALhigh.BAALlowisforInterconnection
frequencyvalueslessthanScheduledFrequency,andBAALhighisforInterconnection
frequencyvaluesgreaterthanScheduledFrequency.BAALvaluesforeachBalancingAuthority
aredynamicandchangeasInterconnectionfrequencychanges.Forexample,as
InterconnectionfrequencymovesfromScheduledFrequency,theACElimitforeachBalancing
Authoritybecomesmorerestrictive.TheBAALprovideseachBalancingAuthorityadynamic
ACElimitthatisafunctionofInterconnectionfrequency.

CPS2wasnotdesignedtoaddressInterconnectionfrequency.Currently,itmeasurestheability
ofaBalancingAuthoritytomaintainitsaverageACEwithinafixedlimitofplusorminusaMW
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valuecalledL10.Tobecompliant,aBalancingAuthoritymustdemonstrateitsaverageACE
valueduringaconsecutive10ͲminuteperiodwaswithintheL10bound90percentofall10Ͳ
minuteperiodsoveraoneͲmonthperiod.WhilethisstandarddoesrequiretheBalancing
AuthoritytocorrectitsACEtonotexceedspecificbounds,itfailstorecognizeInterconnection
frequency.Forexample,theBalancingAuthoritymaybeincreasingordecreasinggenerationto
meetitsCPS2bounds,evenifthisisadirectionthatreducesreliabilitybymoving
Interconnectionfrequencyfartherfromitsscheduledvalue.CPS2allowsaBalancingAuthority
tobeoutsideitsACEbounds10percentofthetime.Thereare72hourspermonththata
BalancingAuthority’sACEcanbeoutsideitsL10limitsandbecompliantwithCPS2.

Insummary,theproposedBAALrequirementwillprovidedynamiclimitsthatareBalancing
AuthorityandInterconnectionspecific.TheseACEvaluesarebasedonidentified
InterconnectionfrequencylimitstoensuretheInterconnectionreturnstoareliablestatewhen
anindividualBalancingAuthority’sACEorInterconnectionfrequencydeviatesintoaregionthat
contributestoomuchrisktotheInterconnection.Thisrequirementreplacesandimproves
uponCPS2,whichisnotdynamic,isnotbasedonInterconnectionfrequency,andallowsfora
BalancingAuthority’sACEvaluetobeunboundedforaspecificamountoftimeduringa
calendarmonth.

ChangeFrom60HztoScheduledFrequency
ThebasefrequencyforthedeterminationofBAALwaschangedfrom60HztoScheduled
Frequency,FS.ThischangewasmadetoresolvealongͲstandingproblemwiththerequirement
asfirstpresentedbytheBalancingResourcesandDemandStandardDraftingTeam.The
followingpresentsinformationaboutthereasonfortheinitialchoiceof60Hzandtheneedto
changethisvaluetoScheduledFrequency.

TheinitialBAALequationsweredevelopedupontheassumptionthattheFrequencyTrigger
Limit(FTL)shouldbebaseduponScheduledFrequencyasshowninthisdraftofthestandard.
DuringinitialdevelopmentofvaluesfortheFTLtheBRDSDTusedadeterministicmethodfor
theselectionofFTLbasedupontheUnderͲFrequencyRelayLimit(UFRL)ofaninterconnection.
SincetheUnderͲFrequencyRelayLimitoftheinterconnectionisfixedtheSDTchosetousea
fixedvalueofstartingfrequencythatwouldmaintainafixedfrequencydifferencebetweenthe
FTLandtheUFRL.Therefore,theBRDSDTchosetobaseBAALonastartingfrequencyof60Hz
undertheassumptionthatiftheUFRLdidnotchangethentheFTLandbasefrequencyshould
notchange.TheBAALFieldTrialwasstartedusingthesevalues.

Shortlyafterthefieldtrialstarted,directedresearchsupportingtheselectionoftheFTLforthe
EasternInterconnectionwascompleted.Unfortunately,themethodsusedtosupportthe
selectionofanFTLfortheEasternInterconnectioncouldnotberepeatedsuccessfullyforthe
otherinterconnections.Includedinthefinalreportwasarecommendationthatamultipleof3
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RealPowerBalancingControlPerformanceStandardBackgroundDocument
to4timestheH1fortheinterconnectioncouldprovideanacceptablealternativechoicefor
determiningtheFTL.1Sincethefieldtrialhadalreadystarted,nochangewasmadetothe
initialFTLfortheEasternInterconnection,butasadditionalinterconnectionsjoinedthefield
trialtheFTLforthesenewinterconnectionswasbasedon3timesH1fortheinterconnection.
ThischangebrokethelinkagebetweenFTLandtheUFRLandeliminatedthejustificationfor
using60Hzastheonlyacceptablestartingfrequency.

AsdataaccumulatedfromtheEasternInterconnectionfieldtrial,itbecameapparentthatTime
ErrorCorrection(TEC)causesadetrimentalreliabilityimpact.TheBACSDTrecognizedthis
problemandinitiatedactionstoprovideacasetoeliminateTECbasedonitseffecton
reliability.ThisactivitycausedtheRBCSDTandlatertheBARCSDTtodeferanyactiononthe
substitutionofScheduleFrequencyfor60HzintheBAALEquationsuntiltheTECissuewas
resolvedbecausetheeliminationofTECwouldeliminatetheneedforchange.WhentheERO
decidedtocontinuetoperformTEC,thatdecisionrelievedtheBARCSDTofresponsibilityfor
thereliabilityimpactofTECandrequiredtheteamtoinsteadconsidertheimpactthatBAAL
couldhaveontheeffectivenessoftheTECprocessandanyconflictsthatwouldoccurwith
otherstandards.

TwoconflictshavebeenidentifiedbetweenBAALandotherstandards.Thefirstisaconflict
betweentheBAALlimitandScheduledFrequencywhenaninterconnectionisattemptingto
performTECbyadjustingtheScheduledFrequencytoeither59.98of60.02Hz.Thesecondisa
conflictthatresultsinBAALprovidinganACElimitthatismorerestrictivethatCPS1whenan
interconnectionisperformingTEC.TheseproblemscanbothberesolvedbybasingtheBAAL
LimitonScheduledFrequencyinsteadof60Hz.Eightgraphsfollowthatshowtheconflict
betweenBAALascurrentlydefinedusing60Hzandotherstandardsandhowthechangefrom
60HztoScheduledFrequencyresolvestheconflict.
ThefirstfourgraphsshowtheconflictthatiscreatedwhileperformingTEC.UnderTECthe
BAALlimitcrossesboththeCPS1=100%lineandtheScheduledFrequencyLineindicatingthe
conflictbetweenBAAL,CPS1andTECwhenBAALisbasedon60Hz.

ThenextfourgraphsshowhowthisconflictisresolvedbyusingScheduledFrequencyasthe
baseforBAAL.WhenBAALisdeterminedinthismannerbothconflictsareresolvedanddonot
appearwiththeimplementationofTEC.

Finally,resolvingthisconflictreducesthedetrimentalimpactthatBAALhasonsomesmaller
BAsontheWesternInterconnectionduringTEC.

1

TheinitialvalueforFTLfortheEasternInterconnectionwassetat50mHz.Threetimeepsilon1fortheEastern
Interconnectionis54mHz.

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59.700
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Figure 1. BAAL Based on 60 Hz w/ Fast TEC



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Figure 3. BAAL Based on 60 Hz Summary



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Figure 8. BAAL Based on Scheduled Frequency Summary

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BAL-001-1 2 – Real
Power Balancing Control
Performance Standard
Background Document
February 2013





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Table of Contents

Table of Contents
TableofContents............................................................................................................................2
Introduction....................................................................................................................................3
BackgroundandRationalebyRequirement...................................................................................4
Requirement1............................................................................................................................4
Requirement2............................................................................................................................5

BALͲ001Ͳ12ͲBackgroundDocument
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RealPowerBalancingControlPerformanceStandardBackgroundDocument

Introduction
Thisdocumentprovidesbackgroundonthedevelopment,testing,andimplementationofBALͲ
001Ͳ12ͲRealPowerBalancingControlStandard.Theintentistoexplaintherationaleand
considerationsfortherequirementsandtheirassociatedcomplianceinformation.
TheoriginalworkforthisstandardwasdonebytheBalancingAuthorityControlsstandard
draftingteam,whichlaterjoinedwiththeReliabilityͲbasedControlStandarddraftingteam.
ThesecombinedteamswererenamedBalanceAuthorityReliabilityͲbasedControlstandard
draftingteam(BARCSDT).
ThepurposeofproposedStandardBALͲ001Ͳ12istomaintainInterconnectionfrequencywithin
predefinedfrequencylimits.ThisdraftstandarddefinesBalancingAuthorityACELimit(BAAL),
andrequiredtheBalancingAuthority(BA)tobalanceitsresourcesanddemandinRealͲtimeso
thatitsclockͲminuteaverageofitsAreaControlError(ACE)doesnotexceeditsBAALformore
than30consecutiveclockͲminutes.
AsaproofofconceptfortheproposedBAALstandard,aBAALfieldtrialwasapprovedbythe
NERCStandardsCommitteeandtheOperatingCommittee.Currentlyparticipatinginthefield
trialare13BalancingAuthoritiesintheEasternInterconnection,26BalancingAuthoritiesinthe
WesternInterconnection,theERCOTBalancingAuthority,andQuebec.ReliabilityCoordinators
forallInterconnectionscontinuetomonitortheperformanceofthoseparticipatingBalancing
AuthoritiesandprovideinformationtosupportmonthlyanalysisoftheBAALfieldtrial.Asof
theendofSeptember2011,noreliabilityissueswiththeBAALfieldtrialhavebeenidentifiedby
anyReliabilityCoordinator.TheWesternInterconnectionhasexperiencedchangesduringthe
fieldtrialwithpotentialdegradationtotransmission;however,noexplicitlinkagehasbeen
determinedbetweenthefieldtrialandthesedegradations.Forfurtherinformationonthe
resultsoftheWesternInterconnection,pleaserefertotheWECCReliabilityͲbasedControlField
TrialReport.
HistoricalSignificance
A1ͲA2ControlPerformancePolicywasimplementedin1973as:
x
x
x

A1requiredtheBalancingAuthority’sACEtoreturntozerowithin10minutesofprevious
zero.
A2requiredthattheBalancingAuthority’saveragedACEforeach10Ͳminuteperiodmustbe
withinlimits.
A1ͲA2hadthreemainshortcomings:
ƒ Lackoftheoreticaljustification
ƒ LargeACEtreatedthesameasasmallACE,regardlessofdirection
ƒ IndependentofInterconnectionfrequency

In1996,anewNERCpolicywasapprovedwhichusedCPS1,CPS2,andDCS.
CPS1isa:
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x
x
x

StatisticalmeasureofACEvariability
MeasureofACEincombinationwiththeInterconnection’sfrequencyerror
BasedonanequationderivedfromfrequencyͲbasedstatisticaltheory
CPS2is:
x
x

DesignedtolimitaControlArea’s(nowknownasaBalancingAuthority)
unscheduledpowerflows
SimilartotheoldA2criteria

TheproposedBALͲ001Ͳ12retainsCPS1,butproposesanewmeasureBAALtoreplaceCPS2.
CurrentlyCPS2:

x Doesnothaveafrequencycomponent.
x CPS2manytimesgivetheBalancingAuthoritytheindicationtomovetheirACE
oppositetowhatwillhelpfrequency.
x OnlyrRequiresBalancingAuthoritiestocomply90percentofthetimeasaminimum.

Background and Rationale by Requirement
Requirement1
R1.TheResponsibleEntityEachBalancingAuthorityshalloperatesuchthattheBalancing
Authority’sControlPerformanceStandard1(CPS1),(ascalculatedinaccordancewith
Attachment1,)isgreaterthanorequalto100percentfortheapplicable
Interconnectioninwhichitoperatesforeach12Ͳmonthperiod,evaluatedmonthly,to
supportInterconnectionfrequency.
BackgroundandRationale
RequirementR1isnotanewrequirement.ItisarestatementofthecurrentBALͲ001Ͳ0.1a
RequirementR1withitsequationandexplanationofitsindividualcomponentsmovedtoan
attachment,Attachment1ͲEquationsSupportingRequirementR1andMeasureM1.This
requirementiscommonlyreferredtoasControlPerformanceStandard1(CPS1).R1isintended
tomeasurehowwellaBalancingAuthorityisabletocontrolitsgenerationandload
managementprograms,asmeasuredbyitsAreaControlError(ACE),tosupportits
Interconnection’sfrequencyoverarollingoneͲyearperiod.
CPS1isameasureofaBalancingAuthority’scontrolperformanceasitrelatestoitsgeneration,
Loadmanagement,andInterconnectionfrequencywhenmeasuredinoneͲminuteaverages
overarollingoneͲyearperiod.IfallBalancingAuthoritiesonanInterconnectionarecompliant
withtheCPS1measure,thentheInterconnectionwillhavearootmeansquare(RMS)
frequencyerrorlessthantheInterconnection’sEpsilon1.
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RealPowerBalancingControlPerformanceStandardBackgroundDocument
ABalancingAuthorityreportsitsCPS1valuetoitsregionalentityeachmonth.Thismonthly
valueprovidestrendingdatatotheBalancingAuthority,NERCresourcessubcommittee,and
othersasneededtodetectchangesthatmayindicatepoorcontrolonbehalfoftheBalancing
Authority.RequirementR1remainsunchanged,althoughthewordingoftherequirementwas
modifiedtoprovideclarity.
Requirement2
R2.EachBalancingAuthorityshalloperatesuchthatitsclockͲminuteaverageofRreporting
ACEdoesnotexceeditsclockͲminuteBalancingAuthorityACELimit(BAAL)formore
than30consecutiveclockͲminutes,itsclockͲminuteBalancingAuthorityACELimit
(BAAL)(ascalculatedinAttachment2,)fortheapplicableInterconnectioninwhichthe
BalancingAuthorityitoperatestosupportInterconnectionfrequency.
BackgroundandRationale
RequirementR2isanewrequirementintendedtoreplaceexistingBALͲ001Ͳ0.1aRequirement
R2,commonlyreferredtoasControlPerformanceStandard2(CPS2).Theproposed
RequirementR2isintendedtoenhancethereliabilityofeachInterconnectionbymaintaining
frequencywithinpredefinedlimitsunderallconditions.

TheBalancingAuthorityACELimits(BAAL)areuniqueforeachBalancingAuthorityandprovide
dynamiclimitsforitsAreaControlError(ACE)valuelimitasafunctionofitsInterconnection
frequency.BAALwasderivedbasedonreliabilitystudiesandanalysiswhichdefineda
FrequencyTriggerLimit(FTL)boundmeasuredinHz.TheFTLisequaltoScheduled
Frequency60Hz,plusorminusthreetimesanInterconnection’sEpsilon1value.Epsilon1is
therootmeansquare(RMS)targetedfrequencyerrorforeachInterconnection,as
recommendedbytheNERCResourcesSubcommitteeandapprovedbytheNERCOperating
Committee.Epsilon1valuesforeachInterconnectionareunique.WhenaBalancingAuthority
exceedsitsBAAL,itisprovidingmorethanitsshareofriskthattheInterconnectionwillexceed
itsFTL.WhenallBalancingAuthoritiesarewithintheirBAAL(highandlow),the
InterconnectionfrequencywillbewithinitsFTLlimits.

BAALisdefinedbytwoequations;BAALlowandBAALhigh.BAALlowisforInterconnection
frequencyvalueslessthanScheduledFrequency60Hz,andBAALhighisforInterconnection
frequencyvaluesgreaterthanScheduledFrequency60Hz.BAALvaluesforeachBalancing
AuthorityaredynamicandchangeasInterconnectionfrequencychanges.Forexample,as
InterconnectionfrequencymovesfromScheduledFrequency60Hz,theACElimitforeach
BalancingAuthoritybecomesmorerestrictive.TheBAALprovideseachBalancingAuthoritya
dynamicACElimitthatisafunctionofInterconnectionfrequency.


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CPS2wasnotdesignedtoaddressInterconnectionfrequency.Currently,itmeasurestheability
ofaBalancingAuthoritytomaintainitsaverageACEwithinafixedlimitofplusorminusaMW
valuecalledL10.Tobecompliant,aBalancingAuthoritymustdemonstrateitsaverageACE
valueduringaconsecutive10ͲminuteperiodwaswithintheL10bound90percentofall10Ͳ
minuteperiodsoveraoneͲmonthperiod.WhilethisstandarddoesrequiretheBalancing
AuthoritytocorrectitsACEtonotexceedspecificbounds,itfailstorecognizeInterconnection
frequency.Forexample,theBalancingAuthoritymaybeincreasingordecreasinggenerationto
meetitsCPS2bounds,evenifthisisadirectionthatreducesreliabilitybymoving
Interconnectionfrequencyfartherfromitsscheduledvalue.CPS2allowsaBalancingAuthority
tobeoutsideitsACEbounds10percentofthetime.Thereare72hourspermonththata
BalancingAuthority’sACEcanbeoutsideitsL10limitsandbecompliantwithCPS2.

Insummary,theproposedBAALrequirementwillprovidedynamiclimitsthatareBalancing
AuthorityandInterconnectionspecific.TheseACEvaluesarebasedonidentified
InterconnectionfrequencylimitstoensuretheInterconnectionreturnstoareliablestatewhen
anindividualBalancingAuthority’sACEorInterconnectionfrequencydeviatesintoaregionthat
contributestoomuchrisktotheInterconnection.Thisrequirementreplacesandimproves
uponCPS2,whichisnotdynamic,isnotbasedonInterconnectionfrequency,andallows
forsignificanthourswhenaBalancingAuthority’sACEvaluetobeunboundedforaspecific
amountoftimeduringacalendarmonthsareunbounded.

ChangeFrom60HztoScheduledFrequency
ThebasefrequencyforthedeterminationofBAALwaschangedfrom60HztoScheduled
Frequency,FS.ThischangewasmadetoresolvealongͲstandingproblemwiththerequirement
asfirstpresentedbytheBalancingResourcesandDemandStandardDraftingTeam.The
followingpresentsinformationaboutthereasonfortheinitialchoiceof60Hzandtheneedto
changethisvaluetoScheduledFrequency.

TheinitialBAALequationsweredevelopedupontheassumptionthattheFrequencyTrigger
Limit(FTL)shouldbebaseduponScheduledFrequencyasshowninthisdraftofthestandard.
DuringinitialdevelopmentofvaluesfortheFTLtheBRDSDTusedadeterministicmethodfor
theselectionofFTLbasedupontheUnderͲFrequencyRelayLimit(UFRL)ofaninterconnection.
SincetheUnderͲFrequencyRelayLimitoftheinterconnectionisfixedtheSDTchosetousea
fixedvalueofstartingfrequencythatwouldmaintainafixedfrequencydifferencebetweenthe
FTLandtheUFRL.Therefore,theBRDSDTchosetobaseBAALonastartingfrequencyof60Hz
undertheassumptionthatiftheUFRLdidnotchangethentheFTLandbasefrequencyshould
notchange.TheBAALFieldTrialwasstartedusingthesevalues.

Shortlyafterthefieldtrialstarted,directedresearchsupportingtheselectionoftheFTLforthe
EasternInterconnectionwascompleted.Unfortunately,themethodsusedtosupportthe
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RealPowerBalancingControlPerformanceStandardBackgroundDocument
selectionofanFTLfortheEasternInterconnectioncouldnotberepeatedsuccessfullyforthe
otherinterconnections.Includedinthefinalreportwasarecommendationthatamultipleof3
to4timestheH1fortheinterconnectioncouldprovideanacceptablealternativechoicefor
determiningtheFTL.1Sincethefieldtrialhadalreadystarted,nochangewasmadetothe
initialFTLfortheEasternInterconnection,butasadditionalinterconnectionsjoinedthefield
trialtheFTLforthesenewinterconnectionswasbasedon3timesH1fortheinterconnection.
ThischangebrokethelinkagebetweenFTLandtheUFRLandeliminatedthejustificationfor
using60Hzastheonlyacceptablestartingfrequency.

AsdataaccumulatedfromtheEasternInterconnectionfieldtrial,itbecameapparentthatTime
ErrorCorrection(TEC)causesadetrimentalreliabilityimpact.TheBACSDTrecognizedthis
problemandinitiatedactionstoprovideacasetoeliminateTECbasedonitseffecton
reliability.ThisactivitycausedtheRBCSDTandlatertheBARCSDTtodeferanyactiononthe
substitutionofScheduleFrequencyfor60HzintheBAALEquationsuntiltheTECissuewas
resolvedbecausetheeliminationofTECwouldeliminatetheneedforchange.WhentheERO
decidedtocontinuetoperformTEC,thatdecisionrelievedtheBARCSDTofresponsibilityfor
thereliabilityimpactofTECandrequiredtheteamtoinsteadconsidertheimpactthatBAAL
couldhaveontheeffectivenessoftheTECprocessandanyconflictsthatwouldoccurwith
otherstandards.

TwoconflictshavebeenidentifiedbetweenBAALandotherstandards.Thefirstisaconflict
betweentheBAALlimitandScheduledFrequencywhenaninterconnectionisattemptingto
performTECbyadjustingtheScheduledFrequencytoeither59.98of60.02Hz.Thesecondisa
conflictthatresultsinBAALprovidinganACElimitthatismorerestrictivethatCPS1whenan
interconnectionisperformingTEC.TheseproblemscanbothberesolvedbybasingtheBAAL
LimitonScheduledFrequencyinsteadof60Hz.Eightgraphsfollowthatshowtheconflict
betweenBAALascurrentlydefinedusing60Hzandotherstandardsandhowthechangefrom
60HztoScheduledFrequencyresolvestheconflict.
ThefirstfourgraphsshowtheconflictthatiscreatedwhileperformingTEC.UnderTECthe
BAALlimitcrossesboththeCPS1=100%lineandtheScheduledFrequencyLineindicatingthe
conflictbetweenBAAL,CPS1andTECwhenBAALisbasedon60Hz.

ThenextfourgraphsshowhowthisconflictisresolvedbyusingScheduledFrequencyasthe
baseforBAAL.WhenBAALisdeterminedinthismannerbothconflictsareresolvedanddonot
appearwiththeimplementationofTEC.


1

TheinitialvalueforFTLfortheEasternInterconnectionwassetat50mHz.Threetimeepsilon1fortheEastern
Interconnectionis54mHz.

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RealPowerBalancingControlPerformanceStandardBackgroundDocument
Finally,resolvingthisconflictreducesthedetrimentalimpactthatBAALhasonsomesmaller
BAsontheWesternInterconnectionduringTEC.

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59.700
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BAALBasedon60Hzw/oTEC

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Figure 2. BAAL Based on 60 Hz w/o TEC

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BAALBasedon60Hzw/FastTEC

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CPS1=100@59.98

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Ͳ2.0

Ͳ2.5

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Figure 1. BAAL Based on 60 Hz w/ Fast TEC



9

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BALͲ001Ͳ12ͲBackgroundDocument
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CPS1=100@60.02

CPS1=100@60.00

CPS1=100@59.98

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Figure 3. BAAL Based on 60 Hz Summary



1
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Figure 5. BAAL Based o Scheduled Frequency w/ Fast TEC

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Figure 7. BAAL Based on Scheduled Frequency w/ Slow TEC


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Figure 8. BAAL Based on Scheduled Frequency Summary

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2

BAL-002-2 – Contingency
Reserve for Recovery from a
Balancing Contingency Event
Standard Background
Document
February 2013





3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Table of Contents

Contents
TableofContents............................................................................................................................2
Introduction....................................................................................................................................3
Background.....................................................................................................................................3
RationalebyRequirement..............................................................................................................4
Requirement1............................................................................................................................4
Requirement2............................................................................................................................4



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ContingencyReserveforRecoveryFromaBalancingContingencyEventStandardBackground
Document

Introduction
TherevisiontoNERCPolicyStandardsin1996createdaDisturbanceControlStandard(DCS).
TheyreplacedB1(AreaControlError(ACE)tozeroin10minutesfollowingadisturbance)and
B2(ACEmuststarttoreturntozeroin1minutefollowingadisturbance)withastandardthat
states:ACEmustreturntoeitherzeroorapreͲdisturbancevalueofACEwithin15Ͳminutes
followingareportabledisturbance.BalancingAuthoritiesarerequiredtoreportall
disturbancesequaltoorgreaterthan80%oftheBalancingAuthority’smostseveresingle
contingency.

BALͲ002wascreatedtoreplaceportionsofPolicy.Itmeasurestheabilityofanapplicableentity
torecoverfromareportableeventwiththedeploymentofreserve.Thereliableoperationof
theinterconnectedpowersystemrequiresthatadequategeneratingcapacitybeavailableatall
timestomaintainscheduledfrequencyandavoidlossoffirmloadfollowinglossoftransmission
orgenerationcontingencies.Thisgeneratingcapacityisnecessarytoreplacegenerating
capacityandenergylostduetoforcedoutagesofgenerationortransmissionequipment.

ThisdocumentprovidesbackgroundonthedevelopmentandimplementationofBALͲ002Ͳ2Ͳ
ContingencyReserveforRecoveryfromaBalancingContingencyEvent.Thisdocumentexplains
therationaleandconsiderationsfortherequirementsandtheirassociatedcompliance
information.BALͲ002Ͳ2wasdevelopedtofulfilltheNERCBalancingAuthorityControls(Project
2007Ͳ05)StandardAuthorizationRequest(SAR),whichincludestheincorporationoftheFERC
Order693directives.TheoriginalSAR,approvedbytheindustry,presumesthereispresently
sufficientcontingencyreserveinalltheNorthAmericanInterconnections.Theunderlyinggoal
oftheSARwastoupdatethestandardtomakethemeasurementprocessmoreobjectiveand
toprovideinformationtotheBalancingAuthorityorReserveSharingGroup,suchthatthe
partieswouldbetterunderstandtheuseofContingencyReservetobalanceresourcesand
demandfollowingaReportableContingencyEvent.Currently,theexistingBALͲ002Ͳ1standard
containsRequirementsspecifictoaReserveSharingGroupwhichthedraftingteambelieves
arecommercialinnatureandisacontractualarrangementbetweenthereservesharinggroup
parties.BALͲ002Ͳ2isintendedtomeasurethesuccessfuldeploymentofcontingencyreserve
byresponsibleentities.Relationshipsbetweentheentitiesshouldnotbepartofthe
performancerequirements,butleftuptoacommercialtransaction.

Clarityandspecificsareprovidedwithseveralnewdefinitions.Additionally,theBALͲ002Ͳ2
eliminatesanyquestiononwhoistheapplicableentityandassurestheapplicableentityisheld
responsiblefortheperformancerequirement.Thedraftingteam’sgoalwastohaveBALͲ002Ͳ2
solelyaperformancestandard.TheprimaryobjectiveofBALͲ002Ͳ2istoassuretheapplicable
entitybalancesresourcesanddemandandreturnsitsAreaControlErrortodefinedvalues
(subjecttoapplicablelimits)followingaReportableBalancingContingencyEvent.
BALͲ002Ͳ2ͲBackgroundDocument
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ContingencyReserveforRecoveryFromaBalancingContingencyEventStandardBackground
Document

Background

ThissectiondiscussesthenewdefinitionsassociatedwithBALͲ002Ͳ2.
BalancingContingencyEvent
ThepurposeofBALͲ002Ͳ2istoensuretheBalancingAuthorityorReserveSharingGroup
balanceresourcesanddemandbyreturningitsAreaControlErrortodefinedvaluesfollowinga
ReportableBalancingContingencyEvent.
ThedraftingteamincludedaspecificdefinitionforaBalancingContingencyEventtoeliminate
anyconfusionandambiguity.ThepriorversionofBALͲ002wasbroadandcouldbeinterpreted
invariousmannersleavingtheabilitytomeasurecomplianceuptotheeyeofthebeholder.By
includingthespecificdefinition,itallowstheResponsibleEntitytofullyunderstandhowto
performandmeetcompliance.Also,FERCOrder693(atP355)directedentitiestoincludea
Requirementthatmeasuresresponseforanyeventorcontingencythatcausesafrequency
deviation.Bydevelopingaspecificdefinitionthatdepictstheeventscausinganunexpected
changetotheResponsibleEntity’sACE,andthenecessaryrequirementsassuresFERC’s
requirementismet.
MostSevereSingleContingency
TheMostSevereSingleContingency(MSSC)termhasbeenwidelyusedwithintheindustry,
however,ithasneverbeendefined.Inordertoeliminateawiderangeofdefinitions,the
draftingteamhasincludedaspecificdefinitiondesignedtofulfilltheneedsofthestandard.In
addition,inordertomeetFERCOrderNo.693(atP356),todevelopacontinentͲwide
contingencyreservepolicy,itwasnecessarytoestablishadefinitionforMSSC.
ContingencyReserve
Mostsystemoperatorsgenerallyhaveagoodunderstandingoftheneedtobalanceresources
anddemandandreturnitsAreaControlErrortodefinedvaluesfollowingaReportable
BalancingContingencyEvent.However,theexistingcontingencyreservedefinitionsprimarily
focusedongenerationandnotdemandsidemanagement.InordertomeetFERCOrderNo.
693(atP356)toincludeaRequirementthatexplicitlyallowsdemandͲsidemanagement(DSM)
tobeusedasaresourceforcontingencyreserve,thedraftingteamelectedtoexpandthe
definitionofContingencyReservetoexplicitlyincludecapacityassociatedwithdemandside
management.
Additionally,conflictexistedbetweenBALͲ002andEOPͲ002astowhenanentitycoulddeploy
itscontingencyreserve.ToeliminatetheconflictandtoassureBALͲ002andEOPͲ002work
togetherandcomplimentedeachother,thedraftingteamclarifiedtheexistingdefinitionof
ContingencyReserve.
ReserveSharingGroupReportingACE

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ContingencyReserveforRecoveryFromaBalancingContingencyEventStandardBackground
Document
Thedraftingteamelectedtoincludethisdefinitiontoprovideclarityformeasurementof
compliancefortheappropriateResponsibleEntity.

OtherDefinitions
Otherdefinitionshavebeenaddedormodifiedtoassureclarificationwithinthestandardand
requirements.

RationalebyRequirement


Requirement1
ExceptwhenanEnergyEmergencyAlertLevel2orLevel3isineffect,theResponsible
EntityexperiencingaReportableBalancingContingencyEventshalldemonstratethat
withinthe
ContingencyEventRecoveryPeriodtheResponsibleEntityreturneditsACEto:
o

Zero,(ifitsPreͲReportableContingencyEventACEwaspositiveorequaltozero),
o lessthesumofthemagnitudesofallsubsequentBalancingContingency
EventsthatoccurwithintheContingencyEventRecoveryPeriod,and
o furtherreducedbythemagnitudeofthedifferencebetween(i)the
ResponsibleEntity’sMostSevereSingleContingency(MSSC)and(ii)thesum
ofthemagnitudesoftheReportableBalancingContingencyEventandall
previousBalancingContingencyEventsthathavenotcompletedtheir
ContingencyReserveRestorationPeriodwhenthesumreferencedinclause
(ii)ofthisbulletisgreaterthanMSSC,
,or

o

ItsPreͲReportableContingencyEventACEValue,(ifitsPreͲReportable
ContingencyEventACEwasnegative),
o lessthesumofthemagnitudesofallsubsequentBalancingContingency
EventsthatoccurwithintheContingencyEventRecoveryPeriod,and

furtherreducedbythemagnitudeofthedifferencebetween(i)theResponsibleEntity’sMost
SevereSingleContingency(MSSC)and(ii)thesumofthemagnitudesoftheReportable
BalancingContingencyEventandallpreviousBalancingContingencyEventsthathavenot
completedtheirContingencyReserveRestorationPeriodwhenthesumreferencedinclause(ii)
ofthisbulletisgreaterthanMSSC
BackgroundandRationale
RequirementR1reflectstheoperatingprinciplesfirstestablishedbyNERCPolicy1.Its
objectiveistoassuretheResponsibleEntitybalancesresourcesanddemandandreturnsits
AreaControlError(ACE)todefinedvalues(subjecttoapplicablelimits)followingaReportable
BALͲ002Ͳ2ͲBackgroundDocument
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ContingencyReserveforRecoveryFromaBalancingContingencyEventStandardBackground
Document
BalancingContingencyEvent.ItrequirestheResponsibleEntitytorecoverfromeventsthat
wouldbelessthanorequaltotheResponsibleEntity’sMSSC.Itestablishesaceilingforthe
amountofContingencyReserveandtimeframetheResponsibleEntitymustdemonstrateina
complianceevaluation.Itisintendedtoeliminatetheambiguitiesandquestionsassociated
withtheexistingstandard.Inaddition,itallowsResponsibleEntity(s)tohaveaclearwayto
demonstratecomplianceandsupporttheInterconnectiontothefullextentofMSSC.
Byincludingnewdefinitions,andmodifyingexistingdefinitions,andtheaboveR1,thedrafting
teambelievesithassuccessfullyfulfilledtherequirementsofFERCOrderNo.693(atP356)to
includeaRequirementthatexplicitlyallowsDSMtobeusedasaresourceforcontingency
reserve.Italsorecognizesthatthelossoftransmissionaswellasgenerationmayrequirethe
deploymentofcontingencyreserve.
Additionally,R1isdesignedtoassuretheapplicableentitymustusereservetocovera
BalancingContingencyEventorthecombinationofanypreviousBalancingContingencyEvents
thathaveoccurredwithinthespecifiedperiod,toaddresstheOrder’sconcernthatthe
applicableentityisrespondingtoeventsandperformanceismeasured.TheReportable
BalancingContingencyEventdefinition,alongwithR1allowsformeasurementofperformance.
ThedraftingteamuseddatasuppliedbyConsortiumforElectricReliabilityTechnology
Solutions(CERTS)tohelpdeterminealleventsthathaveanimpactonfrequency.Datathat
wascompiledbyCERTStoprovideinformationonmeasuredfrequencyeventsispresentedin
Attachment1.Analyzingthedata,onecoulddemonstrateeventsof100MWorgreaterwould
captureallfrequencyeventsforallinterconnections.However,ata100MWreporting
threshold,thenumberofeventsreportedwouldsignificantlyincreasewithnoreliabilitygain
since100MWismorereflectiveoftheoutlyingevents,especiallyonlargerinterconnections.
ThegoalofthedraftingteamwastodesignacontinentͲwidestandardtocapturethemajority
oftheeventsthatimpactfrequency.Reviewingthedata,thedraftingteamconcluded,based
onthemedian,toestablishasinglecontinentͲwidestandard.Thus,someinterconnectionsmay
reportmoreeventsandsomewouldreportless.ToassuretherequirementsoftheFERCOrder
No.693weremet,thedraftingteamdecidedtocapturethemajorityoftheeventshavinga
significantimpactonfrequency;thereportablethresholdwasselectedasthelesserof80%of
theapplicableentity(s)MostSevereSingleContingencyor500MW.
ViolationSeverityLevels
IntheViolationSeverityLevelsforRequirementR1,theimpactoftheResponsibleEntity
recoveringfromaReportableBalancingContingencyEventdependsontheamountofits
ContingencyReserveavailableanddoesithavesufficientresponse.TheVSLtakesthesefactors
intoaccount.
ComplianceCalculation
TodeterminecompliancewithR1,therequiredcontingencyreserveresponseandmeasured
contingencyreserveresponsearecomputedandcomparedasfollows(assumingall
resourcelossvalues,i.e.BalancingContingencyEvents,arepositive):
BALͲ002Ͳ2ͲBackgroundDocument
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ContingencyReserveforRecoveryFromaBalancingContingencyEventStandardBackground
Document
• Therequiredcontingencyreserveresponseequalsthelesserofthemegawatt
lossoftheReportableBalancingContingencyEvent,and,theMostSevereSingle
ContingencyminusthesumofthemegawattlossesofanypreviousBalancing
ContingencyEventswhosestartprecededthestartoftheReportableBalancing
ContingencyEventbylessthanthesumoftheContingencyEventRecoveryPeriod
andContingencyReserveRestorationPeriod.
• Themeasuredcontingencyreserveresponseisequaltooneofthefollowing:
o IfthePreͲReportableContingencyEventACEValueisgreaterthanorequal
tozero,thenthemeasuredcontingencyreserveresponseequals(a)the
megawattvalueoftheReportableBalancingContingencyEventplus(b)the
mostpositiveACEvaluewithinitsContingencyEventRecoveryPeriod(and
followingtheoccurrenceofthelastsubsequentevent,ifany)plus(c)the
sumofthemegawattlossesofsubsequentBalancingContingencyEvents
occurringwithintheContingencyEventRecoveryPeriodoftheReportable
BalancingContingencyEvent.
o IfthePreͲReportableContingencyEventACEValueislessthanzero,thenthe
measuredcontingencyreserveresponseequals(a)themegawattvalueof
theReportableBalancingContingencyEventplus(b)themostpositiveACE
valuewithinitsContingencyEventRecoveryPeriod(andfollowingthe
occurrenceofthelastsubsequentevent,ifany)plus(c)thesumofthe
megawattlossesofsubsequentBalancingContingencyEventsoccurring
withintheContingencyEventRecoveryPeriodoftheReportableBalancing
ContingencyEvent,minus(d)thePreͲReportableContingencyEventACE
Value.
• ComplianceiscomputedasfollowsonCRForm1inordertodocumentall
BalancingContingencyEventsusedincompliancedetermination:
o Iftherequiredcontingencyreserveresponseislessthanorequaltozero,
thentheReportableBalancingContingencyEventComplianceequals100
percent.
o Iftherequiredcontingencyreserveresponseisgreaterthanzero,
ƒ

andthemeasuredcontingencyreserveresponseisgreaterthanor
equaltotherequiredcontingencyreserveresponse,thenthe
ReportableBalancingContingencyEventComplianceequals100
percent.

ƒ

andthemeasuredcontingencyreserveresponseislessthanorequal
tozero,thentheReportableBalancingContingencyEventCompliance
equals0percent.

ƒ

andthemeasuredcontingencyreserveresponseislessthanthe
requiredcontingencyreserveresponsebutgreaterthanzero,then

BALͲ002Ͳ2ͲBackgroundDocument
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ContingencyReserveforRecoveryFromaBalancingContingencyEventStandardBackground
Document
theReportableBalancingContingencyEventComplianceequals100%
*(1–((requiredcontingencyreserveresponse–measured
contingencyreserveresponse)/requiredcontingencyreserve
response)).

Theabovecomputationscanbeexpressedmathematicallyinthefollowing7sequentialsteps,
labeledas[1Ͳ7],where:
ACE_BEST–mostpositiveACEduringtheContingencyEventRecoveryPeriodoccurringafter
thelastsubsequentevent,ifany(MW)
ACE_PREͲPreͲReportableContingencyEventACEValue(MW)
COMPLIANCEͲReportableBalancingContingencyEventCompliancepercentage(0Ͳ100%)
MEAS_CR_RESPͲmeasuredcontingencyreserveresponsefortheReportableBalancing
ContingencyEvent(MW)
MSSC–MostSevereSingleContingency(MW)
MW_LOSTͲmegawattlossoftheReportableBalancingContingencyEvent(MW)
REQ_CR_RESP–requiredcontingencyreserveresponsefortheReportableBalancing
ContingencyEvent(MW)
SUM_PREVͲsumofthemegawattlossesofanypreviousBalancingContingencyEventswhose
startprecedesthestartoftheReportableBalancingContingencyEventbylessthanthesumof
theContingencyEventRecoveryPeriodandContingencyReserveRestorationPeriod(MW)
SUM_SUBSQͲsumofthemegawattlossesofsubsequentBalancingContingencyEvents
occurringwithintheContingencyEventRecoveryPeriodoftheReportableBalancing
ContingencyEvent(MW)


REQ_CR_RESP=minimumofMW_LOST,and,(MSSC–SUM_PREV)[1]
IfACE_PREisgreaterthanorequalto0,then
MEAS_CR_RESP=MW_LOST+ACE_BEST+SUM_SUBSQ[2]

IfACE_PREislessthan0,then
MEAS_CR_RESP=MW_LOST+ACE_BEST+SUM_SUBSQ–ACE_PRE[3]

IfREQ_CR_RESPislessthanorequalto0,thenCOMPLIANCE=100[4]

BALͲ002Ͳ2ͲBackgroundDocument
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ContingencyReserveforRecoveryFromaBalancingContingencyEventStandardBackground
Document
IfREQ_CR_RESPisgreaterthan0,and,
MEAS_CR_RESPisgreaterthanorequaltoREQ_CR_RESP,then
COMPLIANCE=100[5]

IfREQ_CR_RESPisgreaterthan0,and,MEAS_CR_RESPislessthanorequalto0,then
COMPLIANCE=0[6]

IfREQ_CR_RESPisgreaterthan0,and,MEAS_CR_RESPisgreaterthan0,and,
MEAS_CR_RESPislessthanREQ_CR_RESP,then
COMPLIANCE=100*(1–((REQ_CR_RESP–MEAS_CR_RESP)/REQ_CR_RESP))[7]



Requirement2
R2.ExceptduringtheDisturbanceRecoveryPeriodandContingencyReserveRecovery
Period,orduringanEnergyEmergencyAlertLevel2or3,eachResponsibleEntity
shallmaintainanamountofContingencyReserveatleastequaltoitsMostSevere
SingleContingency.
BackgroundandRationale
R2establishesauniformcontinentͲwidecontingencyreserverequirement.R2establishesa
requirementthatcontingencyreservebeatleastequaltoitsMostSevereSingleContingency.
ByincludingadefinitionofMostSevereSingleContingencyandR2,aconsistentuniform
continentͲwidecontingencyreserverequirementhasbeenestablished.Itsgoalistoassure
thattheResponsibleEntitywillhavesufficientcontingencyreservethatcanbedeployedto
meetR1.
FERCOrder693(atP356)directedBALͲ002bedevelopedasacontinentͲwidecontingency
reservepolicy.R2fulfillstherequirementassociatedwiththerequiredamountofcontingency
reserveaResponsibleEntitymusthaveavailabletorespondtoaReportableBalancing
ContingencyEvent.WithinFERCOrder693(atP336)theCommissionnotedthatthe
appropriatemixofoperatingreserve,spinningreserveandnonͲspinningreserveshouldbe
addressed.However,theOrderpredatedtheapprovalofthenewBALͲ003,whichaddresses
frequencyresponsivereserveandtheamountoffrequencyresponseobligation.Withthe
developmentofBALͲ003,andtheassociatedreliabilityperformancerequirement,thedrafting
teambelievesthat,withR2ofBALͲ002andtheapprovalofBALͲ003,theCommission’sgoalsof
acontinentͲwidecontingencyreservespolicyismet.ThesuitesofBALstandards(BALͲ001,
BALͲ002,andBALͲ003)areallperformanceͲbased.Withthesuiteofstandardsandthespecific
BALͲ002Ͳ2ͲBackgroundDocument
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ContingencyReserveforRecoveryFromaBalancingContingencyEventStandardBackground
Document
requirementswithineachrespectivestandard,acontinentͲwidecontingencypolicyis
established.
IntheViolationSeverityLevelsforRequirementR1,theimpactoftheResponsibleEntity
recoveringfromaReportableBalancingContingencyEventdependsontheamountofits
ContingencyReserveavailableanddoesithavesufficientresponse.TheVSLtakesthesefactors
intoaccount.


BALͲ002Ͳ2ͲBackgroundDocument
February,2013



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ContingencyReserveforRecoveryFromaBalancingContingencyEventStandardBackground
Document

Attachment 1
NERC Interconnections 2009-2012
Frequency Events Loss MW Statistics

For: NERC BARC Standard Drafting Team
Prepared by: CERTS
Date: November 2, 2012

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ContingencyReserveforRecoveryFromaBalancingContingencyEventStandardBackground
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ContingencyReserveforRecoveryFromaBalancingContingencyEventStandardBackground
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ContingencyReserveforRecoveryFromaBalancingContingencyEventStandardBackground
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ContingencyReserveforRecoveryFromaBalancingContingencyEventStandardBackground
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BALͲ002Ͳ2ͲBackgroundDocument
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15

BALͲ001Ͳ0.1aMappingtoProposedNERCReliabilityStandardBALͲ001Ͳ2
StandardBALͲ001Ͳ0.1a
Comment
ProposedStandardBALͲ001Ͳ2
NERCBoardApproved
R1. EachBalancingAuthorityshall
ThisRequirementhasbeen
RequirementR1
operatesuchthat,onarolling12Ͳ
movedintoBALͲ001Ͳ2
TheResponsibleEntityshalloperatesuchthattheControl
monthbasis,theaverageofthe
RequirementR1
PerformanceStandard1(CPS1),calculatedinaccordancewith
clockͲminuteaveragesofthe
Attachment1,isgreaterthanorequalto100%forthe
BalancingAuthority’sAreaControl
applicableInterconnectioninwhichitoperatesforeach12
Error(ACE)dividedby10B(Bisthe
monthperiod,evaluatedmonthly.
clockͲminuteaverageofthe

BalancingAuthorityArea’s
FrequencyBias)timesthe
ThecalculationequationforCPS1hasbeenmovedtoAttachment
correspondingclockͲminute
1ofBALͲ001Ͳ2.
averagesoftheInterconnection’s
FrequencyErrorislessthana
specificlimit.Thislimitɸ12isa
constantderivedfromatargeted
frequencybound(separately
calculatedforeach

Project 2010-14.1 Balancing Authority Reliability-based
Controls - Reserves
BAL-001-2 Real Power Balancing Control Performance
Mapping Document

BALͲ001Ͳ2RealPowerBalancingControlPerformance
February,2013

BALͲ001Ͳ0.1aMappingtoProposedNERCReliabilityStandardBALͲ001Ͳ2
StandardBALͲ001Ͳ0.1a
Comment
ProposedStandardBALͲ001Ͳ2
NERCBoardApproved
Interconnection)thatisreviewed
andsetasnecessarybytheNERC
OperatingCommittee.
AVGPeriod‫ͳܧܥܣ‬
Ͳ10B


TheequationforACEis:
ACE=(NIAͲNIS)Ͳ10B(FAͲFS)ͲIME
where:
x NIAisthealgebraicsumof
actualflowsonalltielines.
x NISisthealgebraicsumof
scheduledflowsonalltie
lines.
x BistheFrequencyBias
Setting(MW/0.1Hz)forthe
BalancingAuthority.The
constantfactor10converts
thefrequencysettingto
MW/Hz.
x FAistheactualfrequency.
x FSisthescheduled
frequency.FSisnormally60

2 

BALͲ001Ͳ2RealPowerBalancingControlPerformance
February,2013

3 

BALͲ001Ͳ0.1aMappingtoProposedNERCReliabilityStandardBALͲ001Ͳ2
StandardBALͲ001Ͳ0.1a
Comment
ProposedStandardBALͲ001Ͳ2
NERCBoardApproved
Hzbutmaybeoffsetto
effectmanualtimeerror
corrections.
x IMEisthemetererror
correctionfactortypically
estimatedfromthe
differencebetweenthe
integratedhourlyaverage
ofthenettielineflows
(NIA)andthehourlynet
interchangedemand
measurement(megawattͲ
hour).Thistermshould
normallybeverysmallor
zero.
R2. EachBalancingAuthorityshall
RequirementR2
ThisRequirementhasbeen
operatesuchthatitsaverageACE removedfromBALͲ001Ͳ2and
EachBalancingAuthorityshalloperatesuchthatitsclockͲ
foratleast90%ofclockͲtenͲ
replacedwiththeproposed
minuteaverageofReportingACEdoesnotexceedits
minuteperiods(6nonͲoverlapping RequirementR2forBAAL.
clockͲminuteBalancingAuthorityACELimit(BAAL)for
periodsperhour)duringacalendar 
morethan30consecutiveclockͲminutes,ascalculatedin
monthiswithinaspecificlimit,

Attachment2,fortheapplicableInterconnectioninwhich
referredtoasL10.
theBalancingAuthorityoperates.
AVG10Ͳminute(ACEi)чL10

where:

BALͲ001Ͳ2RealPowerBalancingControlPerformance
February,2013

R3. EachBalancingAuthorityproviding ThisRequirementhasbeen
OverlapRegulationServiceshall
movedintotheBALͲ001Ͳ2



4 

Attachment1
ABalancingAuthorityprovidingOverlapRegulationService

BALͲ001Ͳ0.1aMappingtoProposedNERCReliabilityStandardBALͲ001Ͳ2
StandardBALͲ001Ͳ0.1a
Comment
ProposedStandardBALͲ001Ͳ2
NERCBoardApproved
ThecalculationequationforBAALislocatedinAttachment2of
L10=1.65˒10ඥሺെͳͲ‫ܤ‬௜ ሻሺെͳͲ‫ܤ‬ௌ ሻ
BALͲ001Ͳ2.
ɸ10isaconstantderivedfromthe
targetedfrequencybound.It
isthetargetedrootͲmeanͲ
square(RMS)valueoftenͲ
minuteaverageFrequency
Errorbasedonfrequency
performanceoveragiven
year.Thebound,ɸ10,isthe
sameforeveryBalancing
AuthorityAreawithinan
Interconnection,andBsisthe
sumoftheFrequencyBias
SettingsoftheBalancing
AuthorityAreasinthe
respectiveInterconnection.
ForBalancingAuthorityAreas
withvariablebias,thisis
equaltothesumofthe
minimumFrequencyBias
Settings.



AnyBalancingAuthorityreceiving
OverlapRegulationServiceshall
nothaveitscontrolperformance
evaluated(i.e.fromacontrol
performanceperspective,the
BalancingAuthorityhasshiftedall
controlrequirementstothe
BalancingAuthorityproviding
OverlapRegulationService).

BALͲ001Ͳ2RealPowerBalancingControlPerformance
February,2013

R4.


ThisRequirementhasbeen
movedintotheBALͲ001Ͳ2
ApplicabilitySection.

5 

ApplicabilitySection4.1.1
ABalancingAuthorityreceivingOverlapRegulationServiceis
notsubjecttoControlPerformanceStandard1(CPS1)or
BalancingAuthorityACELimit(BAAL)complianceevaluation.


BALͲ001Ͳ0.1aMappingtoProposedNERCReliabilityStandardBALͲ001Ͳ2
StandardBALͲ001Ͳ0.1a
Comment
ProposedStandardBALͲ001Ͳ2
NERCBoardApproved
evaluateRequirementR1(i.e.,
Attachment1.
toanotherBalancingAuthoritycalculatesitsCPS1
ControlPerformanceStandard1or
performanceaftercombiningitsReportingACEand
CPS1)andRequirementR2(i.e.,
FrequencyBiasSettingswiththeReportingACEand
ControlPerformanceStandard2or
FrequencyBiasSettingsoftheBalancingAuthorityreceiving
CPS2)usingthecharacteristicsof
RegulationService.
thecombinedACEandcombined

FrequencyBiasSettings.

StandardBALͲ002Ͳ0
NERCBoardApproved
R1. EachBalancingAuthorityshall
haveaccesstoand/oroperate
ContingencyReservetorespondto
Disturbances.ContingencyReservemay
besuppliedfromgeneration,
controllableloadresources,or
coordinatedadjustmentstoInterchange
Schedules.

R1.1.ABalancingAuthoritymay
electtofulfillitsContingency
Reserveobligationsby
participatingasamemberofa
ReserveSharingGroup.Insuch
cases,theReserveSharingGroup
shallhavethesame
ThisRequirementhasbeen
movedintoBALͲ002Ͳ2
Applicabilityand“Additional
ComplianceInformation”
sections

1.4.

ReserveSharingGroup

4.1.1 ABalancingAuthoritythatisamemberofa
ReserveSharingGroupistheResponsibleEntity
onlyinperiodsduringwhichtheBalancing
Authorityisnotinactivestatusunderthe
applicableagreementorgoverningrulesforthe
ReserveSharingGroup.

BalancingAuthority

TheResponsibleEntitymayuseContingency
ReserveforanyBalancingContingencyEventand
asrequiredforanyotherapplicablestandards.

AdditionalComplianceInformation

4.2.

4.1.

Applicability

BALͲ002Ͳ0MappingtoProposedNERCReliabilityStandardBALͲ002Ͳ2
Comment
ProposedStandardBALͲ002Ͳ2

Project 2010-14.1 Balancing Authority Reliability-based
Controls - Reserves
BAL-002-2 Contingency Reserve for Recovery from a
Balancing Contingency Event Mapping Document

BALͲ002Ͳ2ContingencyReserveforRecoveryfromaBalancingContingencyEvent
February2013

StandardBALͲ002Ͳ0
NERCBoardApproved
responsibilitiesandobligationsas
eachBalancingAuthoritywith
respecttomonitoringand
meetingtherequirementsof
StandardBALͲ002.TheReliability
CoordinatorandPlanning
Authorityshalleachestablisha
setofinterͲregionalandintraͲ
regionalTransferCapabilities
thatisconsistentwithitscurrent
TransferCapabilityMethodology.
R2. EachRegionalReliability
ThisRequirementhasbeen
Organization,subͲRegional
removedfromBALͲ002Ͳ2
ReliabilityOrganizationorReserve
SharingGroupshallspecifyits
ContingencyReservepolicies,
including:

R2.1.Theminimumreserve
requirementforthegroup.

R2.2.Itsallocationamong
members.

R2.3.Thepermissiblemixof



ThisrequirementfallsundertheParagraph81rules.This
requirementdefinesacommercialagreementbetweentheBA
involvedintheRSG.Thisrequirementdoesnotprovideforan
reliabilityoutcomeandifviolatedwouldnotcauseseparation,
instabilityorcascadingoutages.

BALͲ002Ͳ0MappingtoProposedNERCReliabilityStandardBALͲ002Ͳ2
Comment
ProposedStandardBALͲ002Ͳ2

2 

EachBalancingAuthorityor
ReserveSharingGroupshall

ThisRequirementhasbeen
movedintoBALͲ002Ͳ2
RequirementsR1and

BALͲ002Ͳ2ContingencyReserveforRecoveryfromaBalancingContingencyEvent
February2013

R3.




R2.4.Theprocedureforapplying
ContingencyReservein
practice.

R2.5.Thelimitations,ifany,upon
theamountofinterruptible
loadthatmaybeincluded.

R2.6.Thesameportionofresource
capacity(e.g.reservesfrom
jointlyownedgeneration)
shallnotbecountedmore
thanonceasContingency
ReservebymultipleBalancing
Authorities.

StandardBALͲ002Ͳ0
NERCBoardApproved
OperatingReserve–Spinning
andOperatingReserve–
Supplementalthatmaybe
includedinContingency
Reserve.

RequirementR1

BALͲ002Ͳ2

BALͲ002Ͳ0MappingtoProposedNERCReliabilityStandardBALͲ002Ͳ2
Comment
ProposedStandardBALͲ002Ͳ2

3 



RequirementR2

BALͲ002Ͳ2ContingencyReserveforRecoveryfromaBalancingContingencyEvent
February2013

R3.1.Asaminimum,theBalancing
AuthorityorReserve
SharingGroupshallcarryat
leastenoughContingency
Reservetocoverthemost
severesinglecontingency.
AllBalancingAuthorities
andReserveSharingGroups
shallreview,noless
frequentlythanannually,
theirprobable
contingenciestodetermine
theirprospectivemost
severesinglecontingencies.

StandardBALͲ002Ͳ0
NERCBoardApproved
activatesufficientContingency
ReservetocomplywiththeDCS.

x

x

furtherreducedbythemagnitudeofthe
differencebetween(i)theResponsibleEntity’s
MostSevereSingleContingency(MSSC)and(ii)
thesumofthemagnitudesoftheReportable
BalancingContingencyEventandallprevious
BalancingContingencyEventsthathavenot
completedtheirContingencyEventRestoration
Periodwhenthesumreferencedinclause(ii)
ofthisbulletisgreaterthanMSSC,
o

4 

ItsPreͲReportableContingencyEventACEValue,(if

Or,

lessthesumofthemagnitudesofall
subsequentBalancingContingencyEventsthat
occurwithintheContingencyEventRecovery
Period,and
o

Zero,(ifitsPreͲReportableContingencyEventACE
Valuewaspositiveorequaltozero):

3. ExceptwhenanEnergyEmergencyAlertLevel2or3isin
effect,theResponsibleEntityexperiencingaReportable
BalancingContingencyEventshalldemonstratethat
withintheContingencyEventRecoveryPeriodthe
ResponsibleEntityreturneditsACEto:

BALͲ002Ͳ0MappingtoProposedNERCReliabilityStandardBALͲ002Ͳ2
Comment
ProposedStandardBALͲ002Ͳ2

BALͲ002Ͳ2ContingencyReserveforRecoveryfromaBalancingContingencyEvent
February2013

StandardBALͲ002Ͳ0
NERCBoardApproved

5 

2. Except during the Contingency Event Recovery Period
and Contingency Reserve Restoration Period, or during
an Energy Emergency Alert Level 2 or Level 3, each

RequirementR2

BALͲ001Ͳ2



o Furtherreducedbythemagnitudeofthe
differencebetween(i)theResponsibleEntity’s
MostSevereSingleContingency(MSSC)and
(ii)thesumofthemagnitudesofthe
ReportableBalancingContingencyEventand
allpreviousBalancingContingencyEventsthat
havenotcompletedtheirContingencyEvent
RestorationPeriodwhenthesumreferenced
inclause(ii)ofthisbulletisgreaterthan
MSSC.

o Lessthesumofthemagnitudeofall
subsequentBalancingContingencyEventsthat
occurwithintheContingencyEventRecovery
Period,and

itsPreͲReportableContingencyEventACEValuewas
negative):

BALͲ002Ͳ0MappingtoProposedNERCReliabilityStandardBALͲ002Ͳ2
Comment
ProposedStandardBALͲ002Ͳ2



R4.1.ABalancingAuthorityshall
returnitsACEtozeroifits
ACEjustpriortothe
ReportableDisturbancewas
positiveorequaltozero.
FornegativeinitialACE
valuesjustpriortothe
Disturbance,theBalancing
AuthorityshallreturnACE
toitspreͲDisturbancevalue.

ABalancingAuthorityorReserve
SharingGroupshallmeetthe
DisturbanceRecoveryCriterion
withintheDisturbanceRecovery
Periodfor100%ofReportable
Disturbances.TheDisturbance
RecoveryCriterionis:



Responsible Entity shall maintain an amount of
Contingency Reserve at least equal to its Most Severe
Single Contingency.

6 

Ofurtherreducedbythemagnitudeofthe
differencebetween(i)theResponsibleEntity’s
MostSevereSingleContingency(MSSC)and(ii)the
sumofthemagnitudesoftheReportable
BalancingContingencyEventandallprevious
BalancingContingencyEventsthathavenot

Olessthesumofthemagnitudesofallsubsequent
BalancingContingencyEventsthatoccurwithinthe
ContingencyEventRecoveryPeriod,and

•Zero,(ifitsPreͲReportableContingencyEventACE
Valuewaspositiveorequaltozero):

ThisRequirementhasbeen
BALͲ002Ͳ0RequirementR4andR4.1toBALͲ002Ͳ2
movedintoBALͲ002Ͳ2
RequirementR1
RequirementR1andintothe
1. ExceptwhenanEnergyEmergencyAlertLevel2or3isin
“ContingencyEventRecovery
effect,theResponsibleEntityexperiencingaReportable
Period”and“Contingency
BalancingContingencyEventshalldemonstratethat
ReserveRestorationPeriod”
withintheContingencyEventRecoveryPeriodthe
definitions.
ResponsibleEntityreturneditsACEto:

BALͲ002Ͳ2ContingencyReserveforRecoveryfromaBalancingContingencyEvent
February2013

R4.

StandardBALͲ002Ͳ0
NERCBoardApproved

BALͲ002Ͳ0MappingtoProposedNERCReliabilityStandardBALͲ002Ͳ2
Comment
ProposedStandardBALͲ002Ͳ2



BALͲ002Ͳ2ContingencyReserveforRecoveryfromaBalancingContingencyEvent
February2013

R4.2.ThedefaultDisturbance
RecoveryPeriodis15
minutesafterthestartofa
ReportableDisturbance.
EachBalancingAuthority
shallhaveaccesstoand/or
operateContingency
Reservetorespondto
Disturbances.Contingency
Reservemaybesupplied
fromgeneration,
controllableloadresources,
orcoordinatedadjustments
toInterchangeSchedules.

StandardBALͲ002Ͳ0
NERCBoardApproved



7 

Aperiodbeginningatthetimethattheresource

ContingencyEventRecoveryPeriod

OFurtherreducedbythemagnitudeofthe
differencebetween(i)theResponsibleEntity’s
MostSevereSingleContingency(MSSC)and(ii)the
sumofthemagnitudesoftheReportable
BalancingContingencyEventandallprevious
BalancingContingencyEventsthathavenot
completedtheirContingencyEventRestoration
Periodwhenthesumreferencedinclause(ii)of
thisbulletisgreaterthanMSSC.

OLessthesumofthemagnitudeofallsubsequent
BalancingContingencyEventsthatoccurwithinthe
ContingencyEventRecoveryPeriod,and

•ItsPreͲReportableContingencyEventACEValue,(ifits
PreͲReportableContingencyEventACEValuewas
negative):

Or,

completedtheirContingencyEventRestoration
Periodwhenthesumreferencedinclause(ii)of
thisbulletisgreaterthanMSSC,

BALͲ002Ͳ0MappingtoProposedNERCReliabilityStandardBALͲ002Ͳ2
Comment
ProposedStandardBALͲ002Ͳ2

BALͲ002Ͳ2ContingencyReserveforRecoveryfromaBalancingContingencyEvent
February2013

R5. EachReserveSharingGroupshall ThisRequirementhasbeen
complywiththeDCS.AReserveSharing
movedintoBALͲ002Ͳ2
Groupshallbeconsideredina
RequirementR1and
ReportableDisturbancecondition
ReserveSharingGroup
wheneveragroupmemberhas
ReportingACE
experiencedaReportableDisturbance
andcallsfortheactivationof
ContingencyReservesfromoneormore
othergroupmembers.(Ifagroup
memberhasexperiencedaReportable
Disturbancebutdoesnotcallforreserve
activationfromothermembersofthe
ReserveSharingGroup,thenthat
membershallreportasasingle
BalancingAuthority.)Compliancemay
bedemonstratedbyeitherofthe
followingtwomethods:

StandardBALͲ002Ͳ0
NERCBoardApproved

x

furtherreducedbythemagnitudeofthe
o

8 

lessthesumofthemagnitudesofall
subsequentBalancingContingencyEventsthat
occurwithintheContingencyEventRecovery
Period,and
o

Zero,(ifitsPreͲReportableContingencyEventACE
Valuewaspositiveorequaltozero):

2. ExceptwhenanEnergyEmergencyAlertLevel2or3isin
effect,theResponsibleEntityexperiencingaReportable
BalancingContingencyEventshalldemonstratethat
withintheContingencyEventRecoveryPeriodthe
ResponsibleEntityreturneditsACEto:

RequirementR1

BALͲ002Ͳ2

Aperiodnotexceeding90minutesfollowingtheendof
theContingencyEventRecoveryPeriod.

ContingencyReserveRestorationPeriod:

outputbeginstodeclinewithinthefirstoneͲ
minuteintervalthatdefinesaBalancing
ContingencyEvent,andextendsforfifteenminutes
thereafter.

BALͲ002Ͳ0MappingtoProposedNERCReliabilityStandardBALͲ002Ͳ2
Comment
ProposedStandardBALͲ002Ͳ2



BALͲ002Ͳ2ContingencyReserveforRecoveryfromaBalancingContingencyEvent
February2013

R5.1.TheReserveSharingGroup
reviewsgroupACE(or
equivalent)anddemonstrates
compliancetotheDCS.Tobein
compliance,thegroupACE(orits
equivalent)mustmeetthe
DisturbanceRecoveryCriterion
aftertheschedulechange(s)
relatedtoreservesharinghave
beenfullyimplemented,and
withintheDisturbanceRecovery
Period.

or

R5.2.TheReserveSharingGroup
reviewseachmember’sACEin
responsetotheactivationof
reserves.Tobeincompliance,a
member’sACE(oritsequivalent)
mustmeettheDisturbance
RecoveryCriterionafterthe
schedulechange(s)relatedto
reservesharinghavebeenfully

StandardBALͲ002Ͳ0
NERCBoardApproved

x

9 

o Furtherreducedbythemagnitudeofthe
differencebetween(i)theResponsibleEntity’s
MostSevereSingleContingency(MSSC)and
(ii)thesumofthemagnitudesofthe
ReportableBalancingContingencyEventand
allpreviousBalancingContingencyEventsthat
havenotcompletedtheirContingencyEvent

o Lessthesumofthemagnitudeofall
subsequentBalancingContingencyEventsthat
occurwithintheContingencyEventRecovery
Period,and

ItsPreͲReportableContingencyEventACEValue,(if
itsPreͲReportableContingencyEventACEValuewas
negative):

Or,

differencebetween(i)theResponsibleEntity’s
MostSevereSingleContingency(MSSC)and(ii)
thesumofthemagnitudesoftheReportable
BalancingContingencyEventandallprevious
BalancingContingencyEventsthathavenot
completedtheirContingencyEventRestoration
Periodwhenthesumreferencedinclause(ii)
ofthisbulletisgreaterthanMSSC,

BALͲ002Ͳ0MappingtoProposedNERCReliabilityStandardBALͲ002Ͳ2
Comment
ProposedStandardBALͲ002Ͳ2



R6.1.TheContingencyReserve
RestorationPeriodbeginsat
theendoftheDisturbance
RecoveryPeriod.

ABalancingAuthorityorReserve
SharingGroupshallfullyrestore
itsContingencyReserveswithin
theContingencyReserve
RestorationPeriodforits
Interconnection.



ReserveSharingGroupReportingACE
Atanygiventimeofmeasurementforthe
applicableReserveSharingGroup,thealgebraic
sumoftheACEs(ascalculatedatsuchtimeof
measurement)ofalloftheBalancingAuthorities
thatmakeuptheReserveSharingGroup.



RestorationPeriodwhenthesumreferenced
inclause(ii)ofthisbulletisgreaterthan
MSSC.

x

10

Zero,(ifitsPreͲReportableContingencyEventACE
Valuewaspositiveorequaltozero):

ThisRequirementhasbeen
BALͲ002Ͳ2
movedintotheBALͲ002Ͳ2

RequirementR1and
RequirementR1
“ContingencyEvent
RestorationPeriod”definition
1. ExceptwhenanEnergyEmergencyAlertLevel2or3isin
effect,theResponsibleEntityexperiencingaReportable
BalancingContingencyEventshalldemonstratethat
withintheContingencyEventRecoveryPeriodthe
ResponsibleEntityreturneditsACEto:

BALͲ002Ͳ2ContingencyReserveforRecoveryfromaBalancingContingencyEvent
February2013

R6.

StandardBALͲ002Ͳ0
NERCBoardApproved
implemented,andwithinthe
DisturbanceRecoveryPeriod.

BALͲ002Ͳ0MappingtoProposedNERCReliabilityStandardBALͲ002Ͳ2
Comment
ProposedStandardBALͲ002Ͳ2





BALͲ002Ͳ2ContingencyReserveforRecoveryfromaBalancingContingencyEvent
February2013

R6.2.ThedefaultContingency
ReserveRestorationPeriod
is90minutes.

StandardBALͲ002Ͳ0
NERCBoardApproved

x

furtherreducedbythemagnitudeofthe
differencebetween(i)theResponsibleEntity’s
MostSevereSingleContingency(MSSC)and(ii)
thesumofthemagnitudesoftheReportable
BalancingContingencyEventandallprevious
BalancingContingencyEventsthathavenot
completedtheirContingencyEventRestoration
Periodwhenthesumreferencedinclause(ii)
ofthisbulletisgreaterthanMSSC,
o

11

o Furtherreducedbythemagnitudeofthe
differencebetween(i)theResponsibleEntity’s

o Lessthesumofthemagnitudeofall
subsequentBalancingContingencyEventsthat
occurwithintheContingencyEventRecovery
Period,and

ItsPreͲReportableContingencyEventACEValue,(if
itsPreͲReportableContingencyEventACEValuewas
negative):

Or,

lessthesumofthemagnitudesofall
subsequentBalancingContingencyEventsthat
occurwithintheContingencyEventRecovery
Period,and

o

BALͲ002Ͳ0MappingtoProposedNERCReliabilityStandardBALͲ002Ͳ2
Comment
ProposedStandardBALͲ002Ͳ2









BALͲ002Ͳ2ContingencyReserveforRecoveryfromaBalancingContingencyEvent
February2013

StandardBALͲ002Ͳ0
NERCBoardApproved







12

Aperiodnotexceeding90minutesfollowingtheendof
theContingencyEventRecoveryPeriod.

ContingencyReserveRestorationPeriod:



MostSevereSingleContingency(MSSC)and
(ii)thesumofthemagnitudesofthe
ReportableBalancingContingencyEventand
allpreviousBalancingContingencyEventsthat
havenotcompletedtheirContingencyEvent
RestorationPeriodwhenthesumreferenced
inclause(ii)ofthisbulletisgreaterthan
MSSC.

BALͲ002Ͳ0MappingtoProposedNERCReliabilityStandardBALͲ002Ͳ2
Comment
ProposedStandardBALͲ002Ͳ2



Violation Risk Factor and Violation Severity
Level Assignments

Project 2010-14.1 Balancing Authority Reliability-based Controls
- Reserves
Thisdocumentprovidesthedraftingteam’sjustificationforassignmentofviolationriskfactors(VRFs)
andviolationseveritylevels(VSLs)foreachrequirementinBALͲ001Ͳ2,RealPowerBalancingControl
Performance.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
toBulkElectricSysteminstability,separation,orcascadingfailures,nortohinderrestorationtoa
normalcondition.
BALͲ001Ͳ2RealPowerBalancingControlPerformance
VRFandVSLAssignments–February,2013

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.

BALͲ001Ͳ2RealPowerBalancingControlPerformance
VRFandVSLAssignments–February,2013

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-001-2:

TherearetworequirementsinBALͲ001Ͳ2.Bothrequirementswereassigneda“Medium”VRF.
VRF for BAL-001-2, Requirement R1:


•

FERCGuideline2—Consistencywithinareliabilitystandardexists.Therequirementdoesnot
containsubͲrequirements.BothrequirementsinBALͲ001Ͳ2areassigneda“Medium”VRF.
RequirementR1issimilarinscopetoRequirementR2.

•

FERCGuideline3—Consistencyamongreliabilitystandardsexists.Thisrequirementissimilar
inconcepttothecurrentenforceableBALͲ001Ͳ0.1aStandardRequirementsR1andR2,which
haveanapprovedMediumVRF.

•

FERCGuideline4—ConsistencywithNERC’sDefinitionoftheVRFlevelselectedexists.This
requirement,ifviolated,coulddirectlyaffecttheelectricalstateorthecapabilityoftheBulk
ElectricSystem,ortheabilitytoeffectivelymonitorandcontroltheBulkElectricSystem,but
wouldunlikelyresultintheBulkElectricSysteminstability,separation,orcascadingfailures
sincethisrequirementisanafterͲtheͲfactcalculation,notperformedinRealͲtime.

•

FERCGuideline5—ThisrequirementdoesnotcoͲminglereliabilityobjectives.

BALͲ001Ͳ2RealPowerBalancingControlPerformance
VRFandVSLAssignments–February,2013

3

VRF for BAL-001-2, Requirement R2:


•

FERCGuideline2—Consistencywithinareliabilitystandardexists.Therequirementdoesnot
containsubrequirements.BothrequirementsinBALͲ001Ͳ2areassigneda“Medium”VRF.
RequirementR2issimilarinscopetoRequirementR1.

•

FERCGuideline3—ConsistencyamongReliabilityStandardsexists.Thisrequirementissimilar
inconcepttothecurrentenforceableBALͲ001Ͳ0.1astandardRequirementsR1andR2,which
haveanapprovedMediumVRF.

•

FERCGuideline4—ConsistencywithNERC’sDefinitionoftheVRFlevelselectedexists.This
requirement,ifviolated,coulddirectlyaffecttheelectricalstateorthecapabilityoftheBulk
ElectricSystem,ortheabilitytoeffectivelymonitorandcontroltheBulkElectricSystem,but
wouldunlikelyresultintheBulkElectricSysteminstability,separation,orcascadingfailures
sincethisrequirementisanafterͲtheͲfactcalculation,notperformedinRealͲtime.

•

FERCGuideline5—ThisrequirementdoesnotcoͲminglereliabilityobjectives.



BALͲ001Ͳ2RealPowerBalancingControlPerformance
VRFandVSLAssignments–February,2013

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
eachrequirementinBALͲ001Ͳ2meettheFERCGuidelinesforassessingVSLs:

BALͲ001Ͳ2RealPowerBalancingControlPerformance
VRFandVSLAssignments–February,2013

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.

BALͲ001Ͳ2RealPowerBalancingControlPerformance
VRFandVSLAssignments–February,2013

6

TheNERCVSL
Guidelinesare
satisfiedby
incorporating
percentageof
noncompliance
performancefor
thecalculated
CPS1.

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

ProposedVSLsarenotbinary.
ProposedVSLlanguagedoesnot
includeambiguoustermsand
ensuresuniformityand
consistencyinthe
determinationofpenalties
basedonlyonthepercentageof
intervalstheentityis
noncompliant.

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

BALͲ001Ͳ2RealPowerBalancingControlPerformance
VRFandVSLAssignments–February,2013

R1

R#

Compliance with
NERC VSL
Guidelines

VSLs for BAL-001-2 Requirement R1:


ProposedVSLsdonot
expandonwhatis
requiredinthe
requirement.TheVSLs
assignedonlyconsider
resultsofthecalculation
required.ProposedVSLs
areconsistentwiththe
requirement.

Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement

Guideline 3



7



ProposedVSLsare
basedonsingle
violationsandnota
cumulativeviolation
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
percentageof
noncompliance
performance
forthe
calculated
BAAL.

Thisisanewrequirement.
Asdrafted,theproposed
VSLsdonotlowerthe
currentlevelofcompliance.

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
basedonlyonthe
percentageoftimethe
entityisnoncompliant.

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

BALͲ001Ͳ2RealPowerBalancingControlPerformance
VRFandVSLAssignments–February,2013

R2.

R#

Compliance with
NERC VSL
Guidelines

VSLs for BAL-001-2 Requirement R2:


ProposedVSLsdonot
expandonwhatis
requiredinthe
requirement.TheVSLs
assignedonlyconsider
resultsofthecalculation
required.ProposedVSLs
areconsistentwiththe
requirement.

Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement

Guideline 3



8



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 2010-14.1 Balancing Authority Reliability-based Controls
- Reserves
Thisdocumentprovidesthedraftingteam’sjustificationforassignmentofviolationriskfactors(VRFs)
andviolationseveritylevels(VSLs)foreachrequirementinBALͲ002Ͳ2,ContingencyReservefor
RecoveryfromaBalancingContingencyEvent.EachprimaryrequirementisassignedaVRFandasetof
oneormoreVSLs.Theseelementssupportthedeterminationofaninitialvaluerangeforthebase
penaltyamountregardingviolationsofrequirementsinFERCͲapprovedreliabilitystandards,asdefined
intheEROSanctionGuidelines.
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.
BALͲ002Ͳ2
VRFandVSLAssignments–February,2013

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.

BALͲ002Ͳ2
VRFandVSLAssignments–February,2013

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-002-2:

TherearetworequirementsinBALͲ002Ͳ2.Bothrequirementswereassigneda“Medium”VRF.
VRF for BAL-002-2, Requirement R1:


•

FERCGuideline2—Consistencywithinareliabilitystandardexists.Therequirementdoesnot
containsubͲrequirements.BothrequirementsinBALͲ002Ͳ2areassigneda“Medium”VRF.
RequirementR1issimilarinscopetoRequirementR2.Thisisalsoconsistentwithother
reliabilitystandards(i.e.,BALͲ001Ͳ2,BALͲ003Ͳ1,etc).

•

FERCGuideline3—Consistencyamongreliabilitystandardsexists.Thisrequirementissimilar
inconcepttothecurrentenforceableBALͲ001Ͳ0.1aStandardRequirementsR1andR2,which
haveanapprovedMediumVRF,proposedBALͲ001Ͳ1andBALͲ003Ͳ1.

•

FERCGuideline4—ConsistencywithNERC’sDefinitionoftheVRFlevelselectedexists.This
requirement,ifviolated,coulddirectlyaffecttheelectricalstateorthecapabilityoftheBulk
ElectricSystem,ortheabilitytoeffectivelymonitorandcontroltheBulkElectricSystem,but
violation,initself,wouldunlikelyresultintheBulkElectricSysteminstability,separation,or
cascadingfailuressincethisrequirementisanafterͲtheͲfactcalculation,notperformedinRealͲ
time.

BALͲ002Ͳ2
VRFandVSLAssignments–February,2013

3

•

FERCGuideline5—ThisrequirementdoesnotcoͲminglereliabilityobjectives.

VRF for BAL-002-2, Requirement R2:


•

FERCGuideline2—Consistencywithinareliabilitystandardexists.Therequirementdoesnot
containsubrequirements.BothrequirementsinBALͲ002Ͳ2areassigneda“Medium”VRF.
RequirementR2issimilarinscopetoRequirementR1.Thisisalsoconsistentwithother
reliabilitystandards(i.e.,BALͲ001Ͳ2,BALͲ003Ͳ1,etc).

•

FERCGuideline3—ConsistencyamongReliabilityStandardsexists.Thisrequirementissimilar
inconcepttothecurrentenforceableBALͲ001Ͳ0.1astandardRequirementsR1andR2,which
haveanapprovedMediumVRF,proposedBALͲ001Ͳ1andBALͲ003Ͳ1.

•

FERCGuideline4—ConsistencywithNERC’sDefinitionoftheVRFlevelselectedexists.This
requirement,ifviolated,coulddirectlyaffecttheelectricalstateorthecapabilityoftheBulk
ElectricSystem,ortheabilitytoeffectivelymonitorandcontroltheBulkElectricSystem,but
violation,initself,wouldunlikelyresultintheBulkElectricSysteminstability,separation,or
cascadingfailuressincethisrequirementisanafterͲtheͲfactcalculation,notperformedinRealͲ
time.

•

FERCGuideline5—ThisrequirementdoesnotcoͲminglereliabilityobjectives.



BALͲ002Ͳ2
VRFandVSLAssignments–February,2013

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
eachrequirementinBALͲ002Ͳ2meettheFERCGuidelinesforassessingVSLs:

BALͲ002Ͳ2
VRFandVSLAssignments–February,2013

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.

BALͲ002Ͳ2
VRFandVSLAssignments–February,2013

6

TheNERCVSL
Guidelinesare
satisfiedby
incorporating
percentageof
noncompliance
performancefor
thecalculated
CPS1.

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

ProposedVSLsarenotbinary.
ProposedVSLlanguagedoesnot
includeambiguoustermsand
ensuresuniformityand
consistencyinthe
determinationofpenalties
basedonlyonthepercentageof
intervalstheentityis
noncompliant.

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

BALͲ002Ͳ2
VRFandVSLAssignments–February,2013

R1

R#

Compliance with
NERC VSL
Guidelines

VSLs for BAL-002-2 Requirement R1:


ProposedVSLsdonot
expandonwhatis
requiredinthe
requirement.TheVSLs
assignedonlyconsider
resultsofthecalculation
required.ProposedVSLs
areconsistentwiththe
requirement.

Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement

Guideline 3



7



ProposedVSLsare
basedonsingle
violationsandnota
cumulativeviolation
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.

Thisisanewrequirement.
Asdrafted,theproposed
VSLsdonotlowerthe
currentlevelofcompliance.

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
timetheentityis
noncompliant.

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

BALͲ002Ͳ2
VRFandVSLAssignments–February,2013

R2.

R#

Compliance with
NERC VSL
Guidelines

VSLs for BAL-002-2 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



8



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

Standards Announcement

Project 2010-14.1 Phase 1 of Balancing Authority Reliability-based
Controls: Reserves (BAL-001-2, BAL-002-2 and BAL-013-1)
Just a reminder…
Initial Ballot and Non-Binding Poll is now open through 8 p.m. Eastern April 25, 2013
Now Available

Initial ballots of the following three standards and non-binding polls of the associated Violation Risk
Factors (VRSs) and Violation Severity Levels (VSLs) for Phase 1 of Balancing Authority Reliability-based
Controls: Reserves is open through 8 p.m. Eastern on Thursday, April 25, 2013:
BAL-001-2- Real Power Balancing Control Performance
BAL-002-2- Contingency Reserve for Recovery from a Balancing Contingency Event
BAL-013-1- Large Loss of Load Performance
Background information for this project can be found on the project page.
Instructions

Members of the ballot pools associated with this project may log in and submit their vote for the
standards and opinion in the non-binding polls of the associated VRFs and VSLs by clicking here.
Next Steps

The ballot results will be announced and posted on the project page. The drafting team will consider
all comments received during the formal comment period and, if needed, make revisions to the
standard. If the comments do not show the need for significant revisions, the standard will proceed to
a recirculation ballot.
Standards Development Process

The Standards Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Individual or group. (55 Responses)
Name (31 Responses)
Organization (31 Responses)
Group Name (24 Responses)
Lead Contact (24 Responses)
Contact Organization (24 Responses)
IF YOU WISH TO EXPRESS SUPPORT FOR ANOTHER ENTITY'S COMMENTS WITHOUT
ENTERING ANY ADDITIONAL COMMENTS, YOU MAY DO SO HERE. (10 Responses)
Comments (55 Responses)
Question 1 (38 Responses)
Question 1 Comments (45 Responses)
Question 2 (25 Responses)
Question 2 Comments (45 Responses)
Question 3 (25 Responses)
Question 3 Comments (45 Responses)
Group
Salt River Project
Bob Steiger
Electric Reliability Compliance
Yes
Yes
There is reasonable concern that the large ACE values that the standard permits under certain conditions will cause
excessive unscheduled flow on qualified transmission paths. We believe that this issue can be managed by the
Reliability Coordinator through enforcement of existing standards, but may require changes to current practices.
No
Individual
Tom Siegrist
EnerVision, Inc.
Yes
Yes
Yes
Group
Northeast Power Coordinating Council
Guy Zito
Northeast Power Coordinating Council
No
The need to create the two new terms (RRSG and RRSG Reporting ACE) and the applicability exceptions for BAs that
receives overlap regulation service or participate in the RRSG is not apparent. The Standard should stipulate the
requirements for each BA to meet the CPS1 and BAAL requirements only, regardless of how it arranges for the
regulation services to meet these requirements. Suggest removing the two new terms, and the applicability exception
for BAs receiving overlap regulation service or participating in the RRSG. The current posted version appears to place
requirements on both individual BAs and the RRSG, but the obligations for the latter are not clearly stipulated in the
Standard. There is no need to have the latter (RRSG) requirements stipulated for the RRSG so long as the Standard
places the obligation to each BA to meet the CPS1 and BAAL requirements. The first term (RRSG) is used in the
Applicability section and should be used in R1. However, the proposed Standard allows for overlap and supplemental

regulation and hence a BA may obtain regulation services through these mechanisms only; there is no requirement for
the RRSG to comply with group CPS1 or report RRSG ACE in the Standard, nor is the RRSG Reporting ACE
calculation depicted in the Attachments. We suggest removing these new terms. The term “RRSG” is used in the
Applicability section of the Standard and concern was raised about continued use of new terms not specifically in the
Functional Model, along with any specific tasks and roles for these newly defined “entities”. Should the Functional
Model Working Group (FMWG) review the proposed definition and consider the RRSG as an addition for the NERC
Version 6 of the Functional Model? We suggest that NERC set up a process whereby all proposals for newly defined
entities be vetted and cleared through the FMWG.
No
We do not see the need to create the two new terms (RRSG and RRSG Reporting ACE) and the applicability
exceptions for BAs that receives overlap regulation service or participate in the RRSG. The Standard should stipulate
the requirements for each BA to meet the CPS1 and BAAL requirements only, regardless of how it arranges for the
regulation services to meet these requirements. We suggest removing the two new terms, and the applicability
exception for BAs receiving overlap regulation service or participating in the RRSG. The currently posted version
appears to place requirements on both individual BAs and the RRSG, but the obligations for the latter are not clearly
stipulated in the Standard. There is a need to have the RRSG requirements stipulated for the RRSG so long as the
Standard places the obligation to each BA to meet the CPS1 and BAAL requirements.
Yes
The wording of 4.1.2 should be rearranged to more explicitly define what the “Responsible Entity” is. Responsible entity
should not be capitalized unless it is going to be defined in the NERC Glossary.
Group
Arizona Public Service Company
Janet Smith, Regulatory Affairs Supervisor
Arizona Public Service Company
Yes

Individual
John Tolo
Tucson Electric Power Co
Yes
Yes
Yes
Using the newly-defined term Reporting (ATEC) ACE is a positive change. Using Scheduled Frequency instead of
60Hz in the BAAL calculation is also a positive change.
Individual
Rich Hydzik
Avista
Yes
No
The RBC Field Trial in the WECC provided enough information to determine if RBC had any effects on reliability. The
WECC PWG’s July 2012 report to the WECC OC clearly documented frequency error was increasing over previous
operation under CPS2. It documented increasing frequency in the negative direction in heavy load hours (particularly
morning and evening peaks) and increasing frequency error in the positive direction during light load hours. This report
also shows Epsilon 1 and Epsilon 10 increasing significantly over past CPS2 performance years. Manual time error
corrections and hours of manual time error corrections are approximately double what they had been. The PWG report
documents increasing unscheduled flow events with the ACE Transmission Limit (ATL) being increased or eliminated.
This has continued on into 2013. This indicates that RBC has a negative effect on path flow control and management.
Increasing inadvertent accumulations are also documented in the PWG report. Increasing inadvertent, unscheduled
flow events and curtailments, and prolonged frequency deviations beyond 0.030 Hz are not hallmarks of a reliable
system. No studies, or actual events, have demonstrated that the WECC system can perform for a 2800 MW (G-2)

generation loss with an initial frequency of 59.94 Hz or lower. Additional control problems are created when frequency
deviations beyond 0.030 Hz occur, exceeding governor deadband on generating units (IEEE standard deadband). If
these units are being used for Automatic Generation Control (AGC), they will move to governor control, generally
disabling the AGC functionality. This does not add to system reliability, and likely detracts from it. The RBC formula
advantages larger Balancing Authorities by allowing looser control and wider frequency ranges. Whereas a smaller BA
may see the BAAL limits quickly shrink at deviations near 0.050 Hz, a larger BA can still run a large ACE, creating
inadvertent flow and secondary control problems for smaller BA’s. Finally, loose ACE control effectively eliminates the
effectiveness of the WECC Automatic Time Error Correction system. WECC ATEC depends on CPS2 compliance in
order to ensure that a BA is continuously paying back its accumulated Primary Inadvertent balance. With the loose
limits of RBC, the Primary Inadvertent payback term is small enough that it may not even influence the BA’s AGC
control algorithm. This can be clearly seen by the invreasing WECC frequency deviation beginning with the field trial in
2010. ATEC was implemented in WECC in 2003, and low frequency deviation from 2003-2009 is easily seen the PWG
2012 WECC OC report. R2 is not a frequency control requirement under all conditions, it is a requirement that is used
under normal conditions. It is designed to operate around small frequency deviations. For large frequency deviations,
frequency support is required and measured by ACE recovery under BAL-002 (DCS). With respect to R2/M2, how
many times can a BA exceed BAAL limits for 30 minutes? Can a BA exceed BAAL for 27 minutes every hour? A limit
based on so many minutes exceeding BAAL per month or some similar measure may be more likely to incent the
desired control performance. How do you measure severity if an event happens many times, but never exceeds 30
minutes? Is 29 minutes ok and 31 minutes a risk to the interconnection? Comments: “BAL-001-1 Real Power Balancing
Control Standard Background Document” Page 4 has an illuminating statement. “CPS2 is: Designed to limit a Control
Area’s (now BA) unscheduled power flow.” This is a significant issue in the WECC. Unscheduled power flow becomes
unmanageable without the CPS2 requirement. There is no other way to control BA to BA power flow if a BA is not
required to maintain its Net Actual Interchange within a limit. The summary statement on page 6 is not supported by the
field trials. The summary statement says that RBC improves upon CPS2 by dynamically altering ACE limits based on
frequency. The WECC field trial conclusively demonstrates that frequency control is worse and frequency error is
greater, indicating RBC decreases reliability compared to CPS2. The inability to control path flows effectively, requiring
unscheduled flow mitigation to remain within System Operating Limits, inherently decreases reliable operation. CPS2
takes frequency into account with the frequency component of the ACE equation. To claim that operating to the ACE
equation does not inherently support system frequency is not logical. The CPS2 requirement should be retained, and
the BAAL should not be adopted.
No
Looser AGC control resulting from implementation of BAAL results in unscheduled flow. Increasing unscheduled flow
events significantly impact each participant in the energy markets. Schedules are curtailed to accommodate RBC, thus
favoring one form of generation over another. In this case, variable resources are given an advantage looser control
and other parties are impacted. Although this appears to be an economic issue, any time energy schedules are
curtailed for reliability reasons, reliability is negatively affected.
Individual
Nazra Gladu
Manitoba Hydro
Yes
Although Manitoba Hydro agrees with the definitions, we have the following suggestions: (1) NIA (Actual Net
Interchange) - capitalize the word ‘tie lines’ because it appears in the Glossary of Terms. (2) NIS (Scheduled Net
Interchange) - capitalize the word ‘tie lines’ because it appears in the Glossary of Terms. Also, the words ‘Net
Interchange Actual’ should be rewritten as ‘Net Actual Interchange’ and the word ‘Interchange’ de-capitalized in
‘scheduled Interchange’. (3) Regulation Reserve Sharing Group - capitalize the word ‘regulating-reserve’ because it
appears in the Glossary of Terms. Also, the ‘-‘ should be removed from ‘regulating-reserve’. (4) Reporting ACE capitalize the word ‘net actual interchange’. Also, add ‘net’ to ‘scheduled interchange’ and capitalize, because
definitions appear in the Glossary of Terms. (5) 10 - capitalize ‘frequency bias setting’. (6) IME (Interchange Meter
Error) - the words ‘net interchange actual (NIA)’ should be re-written as ‘Net Actual Interchange’ and capitalized. Also,
de-capitalize the last instance of ‘Interchange’. (7) IATEC (Automatic Time Error Correction) - capitalize the word
interconnection’. (8) H - de-capitalize ‘Hours’ or is this a Clock Hour? (9) PIIaccum - capitalize the words
‘interconnection’, ‘net interchange schedules’, ‘net interchange’, and ‘scheduled frequency’.
Yes
Although Manitoba Hydro is in support of the standard, we have the following clarifying suggestions: (1) 1. (Proposed)
Effective Date in both the Standard and Implementation Plan - remove the “ ‘ “ following the word ‘Trustees’ because it
is not defined this way in the Glossary of Terms. (2) Applicability 4.1.2 - add an ‘s’ on the end of the word ‘period’. In
addition, add the word ‘the’ before ‘governing rules’. (3) Data Retention - capitalize three instances of ‘compliance
enforcement authority’ in this section. (4) R1 - the words ’12 month period’ should be changed to ‘rolling 12 month
basis’ for consistency with the VSL table. (5) R1 - for clarity, ‘it’ should be specified as the ‘Responsible Entity’. (6)
R2/M2 - please clarify if this requirement/measure should refer only to Balancing Authority as opposed to Responsible
Entity? (7) R2 - add the words ‘accordance with’ before ‘Attachment 2’. (8) M1, M2 - the term ‘Energy Management
System’ is not found in the Glossary and should be defined. (9) VSL, R2 and Attachment 1, CPS1 - add a ‘-‘ between

the words ‘clock minutes’ for consistency with the standard. In addition, the words ‘for the applicable Interconnection’
should be added for consistency with the language of R2 and the VSL for R1. (10) General - there is inconsistency
throughout the standard and Attachments with respect to the following words: ‘12 month period’, ‘rolling 12 month
basis’, ‘12-calendar months’, ‘12-month’. We suggest selecting one of these terms and using it throughout the standard
and attachments.
Yes
(1) Section D, Compliance, 1.1 – the paraphrased definition of ‘Compliance Enforcement Authority’ from the Rules of
Procedure is not the standard language for this section. Is there a reason that the standard CEA language is not being
used? (2) Implementation Plan, Regulation Reserve Sharing Group - capitalize the words ‘regulating reserve’ because
they appear in the Glossary of Terms. (3) Implementation Plan, Reporting ACE - capitalize ‘net actual interchange’ and
change ‘scheduled Interchange’ to ‘Net Scheduled Interchange’. (4) Implementation Plan - make same changes to
definitions in Implementation Plan as suggested in Question 1 of this commenting request. (5) VRF/VSL - capitalize
‘bulk electric system’ in both the High Risk Requirement and Medium Risk Requirement sections.
Group
seattle city light
paul haase
seattle city light
Yes
There are differing references to Regulating Reserve Sharing Group and Reserve Sharing Group between BAL-001-2
and BAL-002-2. Seattle City Light recommends consistent terminology across the Standards.
No
Seattle City Light supports the implementation of BAAL limits to replace CPS2, but think this draft needs more work
and should not be implemented as currently written. It appears to have been rushed. Specifically, Seattle experienced
good results in the Reliability Based Controls field trials and supports the RACE and BAAL concepts. However, Seattle
has concerns about the compliance risk introduced by the many new definitions and new types of reserve sharing
groups proposed under this draft. In particular are the relations among Regulation Reserve Sharing Group, Reserve
Sharing Group, and Balancing Authority ability to designate one or another of these groups as responsible entity. For
example, as currently written there may be a possibility of conflict between the applicability of BAL-001-2 and
Requirement R2 of the Standard. As written Applicability Section 4.0 states the Standard is applicable to: 4.1 Balancing
Authority 4.1.2 A balancing Authority that is a member of Regulation Reserve Sharing Group is the Responsible Entity
only in period during which the Balancing Authority is not in active status under the applicable agreement or governing
rules for the Regulation Reserve Sharing Group. 4.2. Regulation Reserve Sharing Group. Further Requirement R2 of
the Standard states that: R2. Each Balancing Authority shall operate such that its clock-minute average of Reporting
ACE does not exceed its clock-minute Balancing Authority ACE Limit (BAAL) for more than 30 consecutive
clock-minutes, as calculated in Attachment 2, for the applicable Interconnection in which the Balancing Authority
operates.[Violation Risk Factor: Medium] [Time Horizon: Real-time Operations] Seattle finds the Standard is not clear if
requirement R.2 is applicable to the Regulation Reserve Sharing Group as a group or to all BAs individually
participating in Regulation Reserve Sharing Group. As currently written a BA can argue that R.2 is not applicable if they
are participating in Regulation Reserve Sharing Group, and Seattle is not sure if this was the intent of the Standard
Drafting Team. Another example is that Attachment 1 used to describe how to calculate CPS1 does not appear to be
complete. It needs to be revised to include the methodology for calculating the CPS1 for the Regulation Reserve
Sharing Group. Seattle is also concerned that BAL-001-2 R2 “…more than 30 consecutive clock-minutes…”
requirement represents too long a time, and should be changed to a shorter time frame to better reflect the existing and
proposed sub-hour scheduling windows and other Standards limiting the time that a Balancing Authority is not
positively supporting system frequency.
Yes
The Guidelines document purported to address issues such as those discussed in question 2 above will not be
available for review until summer 2013. Lacking such a document, Seattle City Light cannot support this draft of BAL001-2.
Group
MRO NERC Standards Review Forum
Russel Mountjoy-Secretary
MRO
No
We don’t understand the reasoning for these new definitions. Balancing Authorities have an Area Control Error. The
standards presently allow for overlap and supplemental regulation that allow a BA to obtain regulation services, which
appears to be the driver for these definitions. We also cannot find in a SAR associated with this project that proposes to
change BAL-001. While the Reliability Based Control standard is referenced in the changes, RBC deals with a 30

minute limit on ACE and not redefinition of ACE and the creation of new entities.
Assuming we are wrong and that the drafting team has authority under their SAR to modify BAL-001, we have the
following comments. 1) Unless there is justification we missed, the new definitions should be removed. 2) With regard
to the ACE equation and the WECC ATEC term, we recommend that the ACE equation be simplified and made such
that it would work with any interconnection. We recommend the term IATEC be changed to ITC, which would stand for
Tertiary Control. (Alternatively, clarify that IATEC is equal to ITC. This way the reporting and operating number would
be the same.) The balancing standards should limit the magnitude of TC to a value such as 20% of Bias. This would
work for both the WECC and HQ approach to controlling time error and assisting in inadvertent interchange
management (WECC). It would also give the Eastern Interconnection a tool to reduce the number of Time Error
Corrections, which will be important if we want to encourage generators to reduce their dead-bands under BAL-003-1.
Yes
1) The implementation plan does not include any mention of the WECC Automatic Time Error Correction in the
definition of Reporting ACE. This deficiency needs corrected as was done in the BAL-001-2 document. The NSRF
believes the drafting team provided the correct definition in the BAL-001-2 document and therefore this should not be a
significant change to the implementation plan or standard. 2) Additionally, it is not clear how a minute that has bad data
should be treated in the determination of a 30 minute period under BAAL. This issue needs to be clarified, especially if
the minute with bad data happens to be the first or last minute. The NSRF is not asking for a change to the standard,
just a clear statement for the purposes of documenting compliance.
Individual
Anthony Jablonski
ReliabilityFirst

No
ReliabilityFirst votes in the Negative due to the “Regulation Reserve Sharing Group” being an applicable Entity and the
fact that there is no functional or Registered Entity defined as a “Regulation Reserve Sharing Group”. Absent any
Entities registered as a “Regulation Reserve Sharing Group”, compliance cannot be assessed against this entity, thus
making any requirements applicable to the “Regulation Reserve Sharing Group” unenforceable.
Individual
Joe Tarantino
SMUD
No
While the definitions are acceptable, terminology within the standards that call these discrete entities would be better
identified as an overarching Reserve Sharing Group that would encompass the various terms: RRSG, RRSGRA ect.
Recommend replacing all unique terminology to only include the Reserve Sharing Group in the BAL-001.
See comment in response #1.
Group
SPP Standards Review Group
Robert Rhodes
Southwest Power Pool
Yes
No
With the introduction of the Regulating Reserve Sharing Group there appears to be a registration gap. There currently
isn’t a Regulating Reserve Sharing Group entity in the Functional Model. It would appear that such a registration would
have to be made in order to be able to hold the Regulation Reserve Sharing Group accountable for compliance
purposes. Providing this is done, then R1 and R2 should reflect the applicability to both the Balancing Authority and the
Regulation Reserve Sharing Group. As written R1 requires any applicable BA to maintain CPS1 for the Interconnection
within which it operates at 100 percent or higher. The rolling 12-month calculation needs additional clarification also.
We suggest the requirement should be rewritten to read: The Responsible Entity shall operate such that its Control
Performance Standard 1 (CPS1), calculated based on the applicable Interconnection in which it operates in
accordance with Attachment 1, is greater than or equal to 100 percent for each consecutive 12-month period. Each
consecutive 12-month period shall be evaluated monthly. As written, R2 applies only to a Balancing Authority. It should
be reworded to apply to both a Balancing Authority or Regulation Reserve Sharing Group as is R1. Substitute
Responsible Entity for Balancing Authority in the requirement. Likewise we would suggest deleting the comma following

‘Attachment 2’ in R2. This links the ending phrase of the sentence to the calculation, where it should be, more tightly. In
the last line of Attachment 2, insert ‘Overlap’ in front of ‘Regulation Service’.
Yes
Add an ‘s’ to ‘period’ in the 2nd line of 4.1.2 in the Applicability Section. Replace ‘greater’ with ‘more’ in the Moderate,
High and Severe VSLs for R2. On Page 7 of the Background Document, in the 4th line of the 3rd paragraph, replace
‘that’ with ‘than’ in front of CPS1.
Individual
Jim Cyrulewski
JDRJC Associates LLC
Agree
Midwest ISO
Individual
Greg Travis
Idaho Power Company
Yes

Yes
I believe that operating under the BAAL does not pose a threat to reliability and could help mitigate variable resource
integration provided that BAs do not stress the limits during normal operations. If BAs could be encouraged to follow
expected changes in system demand reasonably close during normal conditions then the system could more readily
absorb unexpected events. However, I'm not sure how this can be addressed within a standard.
Group
PacifiCorp
Ryan Millard
PacifiCorp
Yes
PacifiCorp supports this draft.
No
Individual
Michael Falvo
Independent Electricity System Operator
No
We do not see the need to create these terms. We understand that the first term (RRSG) is used in the applicability
section and arguable in R1. However, the proposed standard allows for overlap and supplemental regulation and
hence a BA may obtain regulation services through these mechanisms only; there is no requirement for the RRSG to
comply with group CPS1 or report RRSG ACE in the standard, nor is the RRSG Reporting ACE calculation depicted in
the Attachments. We suggest removing these new terms. Furthermore, since the term RRSG is in the applicability
section of the standard, it implies that this is a new functional entity. In order for this term to have applicability, it needs
to have defined roles. This definition should be vetted through the functional model working group and included in the
functional model PRIOR to being included in BAL-001.
No
While we do not see the need to create the two new terms (RRSG and TTSG Reporting ACE), if the terms were to be
included, the term RRSG should be vetted through the functional model working group PRIOR to including it in this
standard as it appears to be a new functional entity. As such, it’s roles should be defined in the functional model prior to
being incorporated into any NERC standards. We do not see the need to create the two new terms (RRSG and RRSG
Reporting ACE) and the applicability exceptions for BAs that receives overlap regulation service or participate in the
RRSG. The standard should stipulate the requirements for each BA to meet the CPS1 and BAAL requirements only,
regardless of how it arranges for the regulation services to meet these requirements. We suggest removing the two
new terms, and the applicability exception for BAs receiving overlap regulation service or participating in the RRSG.
We generally supported the previous draft that stipulates the requirements for each BA. We are unable to support the
currently posted version as it appears to place requirements on both individual BAs and the RRSG but the obligations

for the latter is not clearly stipulated in the standard. At any rate, we do we see a need to have that latter (RRSG)
requirements stipulated for the RRSG so long as the standard places obligation to each BA to meet the CPS1 and
BAAL requirements.
Individual
Howard F. Illian
Energy Mark, Inc.
Yes
Yes
Yes
Individual
Don Schmit
Nebraska Public Power District

No
The applicability section of the standard allows for periods of time when a BA may be responsible for meeting the
requirements of this standard and times when a Regulation Reserve Sharing Group may be responsible for meeting
the requirements of this standard. However R1 requires calculating a 12 month average CPS 1. Neither the
requirement nor the attachment address how a responsible entity is to handle those periods, which may be portions of
a month, day or hour when they are not responsible for meeting the requirements. If the period is to be treated as bad
data, the standard or attachment that details the calculation needs to specify how those periods are handled. The term
“active status” used in section 4.1.2 is not a defined term and may not be included in any regulation reserve sharing
agreements. There should be more clarity around this term. Given the concerns noted above, are there minimum time
periods when a regulation reserve sharing group may not be in “active status”. For example, can a regulation reserve
sharing pool be inactive for a portion of an hour, or conversely only be active for a portion of the hour? The standard
needs more clarification on what active status means and how frequently the status can change.
Group
SERC OC Standards Review Group
Stuart Goza
Tennessee Valley Authority
Yes
We are concerned that the term “Reporting ACE” used in this definition has a different historic meaning than what is
being formalized in this proposed standard. We recommend labeling this term as “Regulation Reporting ACE.”
: We do not believe it is appropriate to include a region or interconnection specific definition in a continent-wide
standard. However, we would not object to including a generic term for time-control adjustment. These comments were
also supported by Ron Carlsen with Southern Company. The comments expressed herein represent a consensus of
the views of the above named members of the SERC OC Standards Review Group only and should not be construed
as the position of the SERC Reliability Corporation, or its board or its officers.
Individual
Kenneth A Goldsmith
Alliant Energy
Agree
MRO NSRF
Group
PJM Interconnection, L.L.C
Stephanie Monzon
PJM Interconnection, L.L.C

No
PJM disagrees with the Interconnection specific inclusion of IATEC in the Reporting ACE definition. The definition of
ACE is internationally recognized. It is inappropriate for the SDT to change that definition because of one region in
North America. PJM believes all Interconnections should adhere to a common ACE equation definition and that
Interconnection specific differences should be addressed through development of a regional standard, as was BAL004-WECC-01.
PJM is, in general, supportive of this standard with the exception noted in comments for question 1.
Individual
Andrew Gallo
City of Austin dba Austin Energy
Agree
ERCOT
Individual
Angela P Gaines
Portland General Electric Company
Yes

PGE is generally supportive of the underlying goal of this standard revision – increased coordination between BAs for
efficiently and reliably, meeting Control Performance Standards through the development of a Regulation Reserve
Sharing Group, or other yet to be named program. However, PGE is concerned the proposed standard does not
adequately address the reliability concerns associated with unscheduled flow and degraded frequency response
metrics that have been witnessed with the current WECC Reliability Based Control pilot program. PGE believes the
unique physical transmission properties of the Western Interconnect dictate a need for increased consideration of
reliability protections for our region prior to the adoption of new nation-wide standards.
Individual
Kathleen Goodman
ISO New England Inc.
No
The need to create the two new terms (RRSG and RRSG Reporting ACE) and the applicability exceptions for BAs that
receives overlap regulation service or participate in the RRSG is not apparent. The Standard should stipulate the
requirements for each BA to meet the CPS1 and BAAL requirements only, regardless of how it arranges for the
regulation services to meet these requirements. Suggest removing the two new terms, and the applicability exception
for BAs receiving overlap regulation service or participating in the RRSG. The current posted version appears to place
requirements on both individual BAs and the RRSG, but the obligations for the latter are not clearly stipulated in the
Standard. There is no need to have the latter (RRSG) requirements stipulated for the RRSG so long as the Standard
places the obligation to each BA to meet the CPS1 and BAAL requirements. The first term (RRSG) is used in the
Applicability section and should be used in R1. However, the proposed Standard allows for overlap and supplemental
regulation and hence a BA may obtain regulation services through these mechanisms only; there is no requirement for
the RRSG to comply with group CPS1 or report RRSG ACE in the Standard, nor is the RRSG Reporting ACE
calculation depicted in the Attachments. We suggest removing these new terms. The term “RRSG” is used in the
Applicability section of the Standard and concern was raised about continued use of new terms not specifically in the
Functional Model, along with any specific tasks and roles for these newly defined “entities”. Should the Functional
Model Working Group (FMWG) review the proposed definition and consider the RRSG as an addition for the NERC
Version 6 of the Functional Model? We suggest that NERC set up a process whereby all proposals for newly defined
entities be vetted and cleared through the FMWG.
No
We do not see the need to create the two new terms (RRSG and RRSG Reporting ACE) and the applicability
exceptions for BAs that receives overlap regulation service or participate in the RRSG. The Standard should stipulate
the requirements for each BA to meet the CPS1 and BAAL requirements only, regardless of how it arranges for the
regulation services to meet these requirements. We suggest removing the two new terms, and the applicability
exception for BAs receiving overlap regulation service or participating in the RRSG. The currently posted version
appears to place requirements on both individual BAs and the RRSG, but the obligations for the latter are not clearly
stipulated in the Standard. There is a need to have the RRSG requirements stipulated for the RRSG so long as the
Standard places the obligation to each BA to meet the CPS1 and BAAL requirements.
The wording of 4.1.2 should be rearranged to more explicitly define what the “Responsible Entity” is. Responsible entity

should not be capitalized unless it is going to be defined in the NERC Glossary. There is a concern that the operations
under the BAL-001 standard will not meet the frequency performance expectation of BAL-003 (e.g., frequency above
59.974 Hz at least 95% of the time for the Eastern Interconnection). If the frequency performance falls below this
target, then the Interconnection Frequency Response Obligation (IFRO) may no longer be adequate for reliability.
Additionally, it could become burdensome to the industry if the IFRO becomes volatile in the upward direction, as
additional frequency response is difficult to obtain and has a rather long lead time for increasing its supply.
Individual
Thad Ness
American Electric Power
No
It is not clear what exact intent the drafting team has in the introduction of the term “Regulation Reserve Sharing
Group”. This term is specified in the Applicability section, so is it the drafting team’s intent to propose that this new term
be established as a new Functional Entity? If that is not the intent, we believe it is mistaken to specify any applicability
to any grouping that does not have formal, registered members.
AEP has suggested modifications regarding scope and content in our responses to Q1 & Q3. Most concerning to us
are the topics raised in our response to Q3 (below).
Yes
We would encourage the drafting team to provide Generator Operators with the appropriate requirements to support
the Balancing Authorities. As currently drafted, the Balancing Authority may be the sole entity responsible for meet the
obligations of the standard, and yet it does not have direct control over the Generator Operator to ensure the BA
receives what is needed. At the least, the BA might need some sort of recourse specified in the event a Generator
Operator is not acting in a cooperative manner (for example, a Generator Operator who refuses to adhere to their
agreed-upon schedule in real time, but is not penalized because they integrate over the hour).
Group
Duke Energy
Greg Rowland
Duke Energy
No
Duke Energy agrees that special provisions may be necessary to capture the combined BAAL performance of two BAs
operating under a Supplemental Regulation agreement so that one BA can’t reset the 30-minute compliance clock of
the other BA with a change to the dynamic interchange; however, we are concerned that these definitions could be
interpreted to mean that three or more BAs could operate as one, sharing regulation, while the Standards lack sufficient
detail behind how the associated interchange of such a group would be tagged or otherwise captured to ensure that the
transmission impact is evaluated and subject to curtailment similar to other interchange. When a BA is formed from
multiple BAs, its anticipated operation, impact on neighboring systems, and readiness to operate are evaluated – in
some cases seams agreements have been required to address adjacent system concerns. The idea that multiple BAs
could get together and form a Regulation Reserve Sharing Group (with the potential to impact neighboring systems no
differently than is a single BA) without such scrutiny could have reliability implications. Regulation Reserve Sharing
Group is not currently included in the NERC Functional Model. The process for registering such a group would have to
be addressed for compliance. The words “regulating reserve” should be capitalized in the definition of RRSG.
Yes
Duke Energy has long supported the Field Trial of the Balancing Authority ACE Limit (BAAL) and supports its adoption
in place of the current CPS2 as proposed in BAL-001-2.
Yes
Duke Energy does not support the definition of Reporting ACE as written. We believe that “ACE” should be defined as
“The difference between the Balancing Authority’s net actual Interchange and its scheduled Interchange, plus its
Frequency Bias obligation, plus any known meter error plus Automatic Time Error Correction (ATEC – If operating in
the Western Interconnection and in the ATEC mode)”; followed with the equation shown and the details of the
variables. “Reporting ACE” should be defined simply as the “The scan rate values of a Balancing Authority’s ACE”.
Though Duke Energy supports the adoption of the BAAL; it’s not clear why all of the other changes to the standard are
needed, nor is it clear how these changes respond to FERC directives. We believe that it should be mentioned that the
BAAL addresses the FERC directive to develop a standard addressing the large loss of load – the BAAL measure will
ensure appropriate response to any event causing the Balancing Authority’s ACE to exceed its BAAL (see comments
to BAL-013 for further details). Duke Energy agrees with the proposed change to the BAAL equation to accommodate
Time-Error Corrections by placing Scheduled Frequency in the numerator and denominator in place of 60 Hz; however
it is not clear why Balancing Authorities under the Field Trial have not yet been afforded the opportunity to incorporate
the same change in the BAAL calculation in their tools. Duke Energy would support allowing the Balancing Authorities
under the Field Trial to make the appropriate changes in their tools to be consistent with the BAAL equation as

proposed, and would support the drafting team updating the tools on the NERC Field Trial website to be consistent with
the current BAL-001-2 posted.
Individual
John Seelke
Public Service Enterprise Group
Agree
PJM Interconnection
Individual
Linda Horn
Wisconsin Electric Power Company
Agree
Midwest ISO
Individual
Don Jones
Texas Reliability Entity
Yes
1) The equation in the definition of Reporting ACE in the Standard is different than the one in the Implementation Plan
(left off the WECC ATEC). 2) The Regulation Reserve Sharing Group Reporting ACE definition is different here than
the Reserve Sharing Group Reporting ACE definition provided in BAL-002—which is correct? (Note “at the time of
measurement” as last part of sentence)
1) The Implementation Plan does not include the WECC ATEC term. The ACE equation should be simplified so that it
can apply to any interconnection. Any Time Error Correction term or alternate tertiary control term added to the ACE
equation should enable any interconnection to control time error and reduce inadvertent interchange. 2) Attachment 2
also needs additional clarification regarding valid/invalid data. If a one-minute frequency sample is determined to not be
valid, how is the 30 consecutive clock-minute count affected? Does the invalid minute count as an exceedance, or does
the count ignore the invalid minute, or does the count start over at 0? 3) For Requirement R2, does there need to be an
exclusion for the 30 consecutive clock-minute average if the BA experiences an EEA event or has a Balancing
Contingency event within the 30 minute period? It seems feasible that if a BA experiences an EEA with extended low
frequency or a Balancing Contingency event with an extended recovery period, that the clock-minute average for R2
might subsequently fail. Is this the intent of the SDT?
The latest changes to the VSLs for R2 made them more confusing. We would suggest re-wording them to state, for
example: “The Balancing Authority exceeded its clock-minute BAAL for more than 30 consecutive clock minutes and
for less than or equal to 45 consecutive clock minutes.”
Individual
Oliver Burke
Entergy Services, Inc. (Transmission)
Agree
SERC OC Standards Review Group
Individual
Brian Murphy
NextEra Energy

Yes
The High Frequency Limit (FTLhigh) calculated as Fs + 3 LVKRXOGEHFKDQJHGWR)V L
Individual
Robert Blohm
Keen Resources Ltd.
Yes
No
Yes

The Frequency Trigger Limit is set too tight at 3 standard deviations. This causes too many initial exceedences of
BAAL as revealed in the field tests. This prompts BAs to wait until enough of them disappear by themselves to make it
feasible to address all of the remainder. But, by waiting, the BA is failing to address the remainder early enough before
they become outright violations. Instead, it would be better for reliability to raise the Frequency Trigger Limit to, say, 4
or 5 standard deviations to reduce the number of initial exceedences of BAAL to the point where it is feasible to
address ALL of them immediately. What reliability is gained by a tighter limit that is feasible only if the BAs wait to
address any and all of the exceedences? Furthermore, no legitimate statistical justification was ever provided for the
tight 3-standard-deviations Frequency Trigger Limit. The very flawed attempt to provide such a justification led to
rejection of the first version of this standard put out for balloting. No further formal technical justification was thereafter
developed on which to base that or a wider limit, despite acknowledgement for a time on the drafting team that it was
needed.
Individual
Bill Fowler
City of Tallahassee
Yes
No
This is not a yes/no question. The City of Tallahassee (TAL) believes that six months is insufficient time to modify the
software, make the changes, and monitor performance in today’s CIP world. Cyber standards have progressed
significantly since the Standards Drafting Team analyzed the potential timeframes for implementation. TAL contends
that 12 months would be more appropriate.
No
this is not a yes/no question.
Individual
Karen Webb
City of Tallahassee
Yes
No
The City of Tallahassee (TAL) believes that six months is insufficient time to modify the software, make the changes,
and monitor performance in today’s CIP world. Cyber standards have progressed significantly since the Standards
Drafting Team analyzed the potential timeframes for implementation. TAL contends that 12 months would be more
appropriate.
No
Individual
Scott Langston
City of Tallahassee
Yes
No
The question above is not a Yes/No question. The City of Tallahassee (TAL) believes that six months is insufficient
time to modify the software, make the changes, and monitor performance in today’s CIP world. Cyber standards have
progressed significantly since the Standards Drafting Team analyzed the potential timeframes for implementation. TAL
contends that 12 months would be more appropriate.
No
Group
PPL NERC Registered Affiliates
Brent Ingebrigtson
LG&E and KU Services
Yes

N/A
LGE and KU Services is a participant in the BAAL Field Test and support the implementation of the BAAL standard
Group
FirstEnergy
Larry Raczkowski
FirstEnergy Corp
Agree
MISO
Group
Western Area Power Administration
Lloyd A. Linke
Western Area Power Administration

No
The impacts of the field trial have not been analyzed thoroughly enough to put this to a vote at this time. In the WECC,
we have seen an increase in frequency deviations, the number of manual time error corrections, coordinated phase
shifter operations, and unscheduled flow during the period of the field trial. It is not entirely clear to what extent the
Field Trial is responsible for these increases. The data collected has not been made available to the individual Entities
for analysis and evaluation. At the NERC level there is some information posted but it is not in great enough detail to be
able to make a decision on the merits or risks associated with the BAAL standard. One piece of information which
seems blatantly missing is the degree to which participating BA’s have detuned their AGC systems for the field trial.
Without this information it seems an objective analysis of the impacts would be impossible. If we are seeing an
increase in the number of frequency excursions yet the participating BA’s have only minimally (or not at all) detuned
their AGC algorithms then we may unknowingly be sitting on the brink of reliability disaster should the standard pass
and BA’ fully detune their AGC systems to take full advantage of the new requirements. This standard seems to be
moving contrary to the general trend of standards development. While all other standards seem to be aiming for
improvements to reliable system operations this standard is going the other direction by considerably relaxing the
Control Performance Standards. It is difficult to understand how a standard which allows a BA to accumulate extremely
large negative ACE – potentially in the minutes just prior to a major MSSC event - could possibly be an improvement
for reliability. From the control required of CPS2, this appears to be a lowering of the bar. The WECC experienced
fewer instances where SOL were exceeded, when there was a ACE Transmission Limit of 4 times L sub 10 during the
RBC Field Trial. Western recommends that the BARC SDT consider establishing an ACE Transmission Limit for the
Western Interconnection. The impacts are not the same for Large Balancing Authorities as they are for small Balancing
Authorities. Under certain conditions, small Balancing Authorities may experience a more narrow operating bandwidth
under the proposed BAL-001-1 than under the existing BAL-001.
Group
MISO Standards Collaborators
Marie Knox
MISO
No
We don’t understand the reasoning for these new definitions. Balancing Authorities have an Area Control Error. The
standards presently allow for overlap and supplemental regulation that allow a BA to obtain regulation services, which
appears to be the driver for these definitions. We also cannot find in a SAR associated with this project that proposes to
change BAL-001. While the Reliability Based Control standard is referenced in the changes, RBC deals with a 30
minute limit on ACE and not redefinition of ACE and the creation of new entities.
Yes
Assuming we are wrong and that the drafting team has authority under their SAR or a specific FERC directive to modify
the definitions in BAL-001, we have the following comments. With regard to the ACE equation and the WECC ATEC
term, we recommend that the ACE equation be simplified and made such that it would work with any interconnection.
We recommend the term IATEC be changed to ITC, which would stand for Time Control. The balancing standards
should limit the magnitude of TC to a value such as 20% of Bias. This would work for both the WECC and HQ
approach to controlling time error and assisting in inadvertent interchange management (WECC). It would also give the
Eastern Interconnection a tool to reduce the number of Time Error Corrections, which will be important if we want to
encourage generators to reduce their deadbands under BAL-003-1.
No

Individual
Christopher Wood
Platte River Power Authority
Agree
Public Service Company of Colorado (Xcel Energy)
Individual
Spencer Tacke
Modesto Irrigation District
No
This concept violates the very definition of a balancing authority (control area).
Need a technical justification for the various Epsilon values specified.
Group
Southern Company: Southern Company Services, Inc; Alabama Power Company; Georgia Power Company; Gulf
Power Company; Mississippi Power Company; Southern Company Generation; Southern Company Generation and
Energy Marketing
Pamela R. Hunter
Southern Company Operations Compliance
Yes

Group
ERCOT
H. Steven Myers
ERCOT ISO
Yes
ERCOT ISO suggests that the drafting team consider adding the following language to the beginning of Requirement
R2: The BAAL measure in R2 is a single event performance measurement similar to BAL-002-2 R1. BAL-002-2 R1
does not apply when a BA is in Emergency Alert Level 2 or 3. During EEA 2 or 3, priority should be given to returning
the system to a secure state. Arguably this should exclusion should apply to all emergency conditions (EEA 1, EEA 2,
and EEA 3). Consistent with the exclusion in BAL-002-2 R1, ERCOT suggests that the SDT consider adding the
language below to BAL-001-2 R2: "'Except when an Energy Emergency Alert Level 2 or Level 3 is in effect' each
Balancing Authorty shall operate such that its clock-minute average of Reporting ACE does not exceed its clock-minute
Balancing Authority ACE Limit (BAAL) for more than 30 consecutive clock-minutes, as calculated in Attachment 2, for
the applicable Interconnection in which the Balancing Authority operates. [Violation Risk Factor: Medium] [Time
Horizon: Real-time Operations]" ERCOT ISO is voting "no" for the preceding reasons. However, if ERCOT ISO's
proposed revisions are adopted, ERCOT ISO would support the standard.
Group
Powerex Corp.
Dan O'Hearn
Powerex Corp.
No
The proposed definitions have not been adequately justified for inclusion in the standard. The background document
does not provide any additional information or reasons for inclusion of these definitions.
Powerex believes that the proposed draft standard is deficient in many respects as highlighted by commenters in the
previous posting period. Specifically Powerex notes the following concerns in the proposed standard that highlight the
inadequacy of the proposed requirements to uphold the reliability of interconnections. If these concerns are not
adequately addressed the resultant standard could lead to degradation in reliability. The deficiencies include: 1) The

proposed standard allows for an entity to be outside of its BAAL limit for 29 minutes and be inside the limit for one
minute, which provides a framework that allows an entity to possibly operate outside of the prescribed bounds 95 % of
the time. The consequences of allowing such operations has not been adequately addressed by the drafting team, and
allowing this standard to move forward with such latitude could lead to reliability issues. 2) The proposed standard does
not restrict or limit BAs during periods of high congestion, when unscheduled flow on the entire system is causing
reliability issues and/or exceedance of limits. Under the proposed standard the transmission path operators and BAs
are forced to deal with unscheduled flows on the system without adequate tools or procedures in place to remedy the
reliability events. During the field trial of the proposed standard these issues have been experienced in the WECC,
where congestion management of non-Qualified and Qualified paths has created various operating issues for the
entities and Reliability Coordinators. The consequences of allowing unlimited use of a transmission system via
unlimited unscheduled flows, without better mechanisms to control flows, could lead to reliability events. The proposed
standard does not provide the authority to the Reliability Coordinators to control and/or propose new operating
procedures (eg. Limiting all BAs in the interconnection to operate within L10 during period of congestion) that mitigate
unscheduled flows that are adversely impacting the transmission grid. This needs to be addressed in this proposed
standard so that during high congestion periods, regardless of system frequency, BAs bring ACE limits within L10 or
some other suitable limitation that decreases the adverse impact. 3) The proposed standard puts no limits on ACE
during times of normal frequency, which allows BAs to inappropriately “lean” on other generation, or to push excessive
amount of energy on to the transmission system. This deficiency allows a BA to obtain energy or push unscheduled
energy across the interties during times that can be economically advantageous to the BA without regard to impacts
upon neighboring BAs, load serving entities and transmission customers. It is paramount that the current standard, with
CPS2, remain in place until such time that the reliability issues associated with the draft standard are resolved.
Powerex believes that the reliability issues with the current draft standard have not been adequately addressed by the
drafting team. The reliability issues that have been previously submitted by commenters raised valid concerns, and the
drafting team has not addressed those specific concerns in their responses. Powerex submits the following subsequent
comments: 1) In Order No. 890, the Federal Energy Regulatory Commission (FERC or the Commission) recognized
the potential for inadvertent energy flows between adjacent BAs to both jeopardize reliability and to cause undue harm
to customers on the grid. Such inadvertent energy flows are driven by the size of each BAAs ACE, but are primarily
contained by CPS2 under the current BAL-001. FERC also made it clear that it was inappropriate for generators within
a BAA to “dump power on the system or lean on other generation...The tiered imbalance penalties adopted in the Final
Rule generally provide a sufficient incentive not to engage is such behavior” The proposed standard will allow entities
to create deliberate inadvertent flows within the standards boundaries, without regard to the impacts and which could
lead to exceedances in SOL due to large ACEs. The proposed performance standard does not address the potential
for a single BA to lean on the grid with deliberate unscheduled energy flows or inadvertent energy, taking any
accumulated benefits for itself and harming other entities on the grid. The detrimental impacts of deliberate inadvertent
flows to load customers and transmission customers on the grid could be substantial when large ACE deviations cause
transmission limit exceedances. It is imperative that the drafting team address this issue in the standard. 2) Various
entities have also expressed concerns regarding the reliability impacts of inadvertent or unscheduled flows. The issues
experienced by entities during the Field Trial were provided in the previous comment period, but the drafting team has
failed to address the comments adequately. Furthermore, the drafting team ignored the concerns and provided a
generic response to commenters from NE ISO, WECC, Tucson, APS, BPA and NPPD. These concerns regarding the
BAAL standard include comments such as: a. Reliability concerns over BAAL limits not accounting for large ACE
excursions b. Increase in transmission limit exceedances c. Interconnection exposed due to the lack of ACE bounding
d. CPS 2 is a more reliable metric e. Allows for more unscheduled power flows and amount of unscheduled
interchange a BA can have is not capped f. WECC average frequency deviation has been increasing g. Elimination of
CPS2 has a detrimental impact on reliability h. Leads to transmission constraints and requires TOPs and RCs to
restrict the unscheduled flows on the system due to a BA unilaterally over or under generating i. WECC has
experienced many SOL violations due to Large ACEs 3) After reviewing the previous comments and responses, it has
become abundantly clear that the drafting team chose to respond to commenters with generic statement such as “The
drafting team conducts a monthly call to review the results from the BAAL field trial. There have not been any reliability
issues raised by any RC during these calls. The drafting team encourages BA’s and RC’s to share any specific
occurrences that they feel have reliability impacts as a result of operating under BAAL.”, but did not specifically
address, revise or enhance the proposed standard based on the comments. These generic statements are not
appropriate by a drafting team and could be considered as dismissive.. The drafting team seems to be suggesting that
the “monthly call” mentioned in the drafting team’s response is the only forum where reliability concerns need to be
addressed. As an example, WECC submitted comments and provided information on RC actions and asked for the
drafting team to remedy the issue in the standard, and I quote “During Phase 3, the Reliability Coordinators (RC)
reported several SOL exceedance associated with high ACE. The SOL exceedances were mitigated when RCs
requested the high ACE value to be reduced to L10.The SDT must address transmission loading issues caused by
high ACE.” The drafting team did not adequately address this issue, which was raised by a regional entity, and
responded by issue a generic statement that since this issue wasn’t discussed on the monthly phone call that these
issues or experiences in WECC are not true reliability issues. It is imperative that the drafting team revisit all those
comments that have been received and make appropriate revisions, and additions to the standard address the
reliability concerns raised by the entities regarding SOL exceedance, transmission loading, and unscheduled flow
issues. 4) Powerex believes that the current field trial has not proven to be more reliable, and it is imperative that the
issues surrounding the increases in frequency error, exceedance of SOL and transmission limits be addressed. There

has been no comparison or evidence provided that shows that the proposed standard is superior in reliability than
CPS2. Several commenters have raised concerns with the elimination of CPS2, and impacts associated with the
increase of frequency error and unscheduled interchange due to large ACE deviations, which pose a greater risk to
reliability than the current CPS2 requirement. The drafting team cannot provide a generic statement that “BAAL was
designed to provide for better control by allowing power flows that do not have a detrimental effect on reliability but
restrict those that do have a detrimental effect on reliability” without providing any evidence or data to test the validity of
those statements. The drafting team has not provided any supporting evidence or data that would validate such a
generic statement, nor has it provided any benefits that were realized during the field trial and resulted in enhanced
reliability. On the contrary, WECC has experienced a degradation of reliability measures, impacts to commercial
transmission customers, as well as reliability issues that required RC intervention during the field trial. Those
detrimental effects of the proposed standard cannot be offset by the drafting team providing generic and unsupported
statements. 5) Powerex believes that the standard should have a BAALHigh and BAALLow in place at all time in order
to manage ACE deviations that may jeopardize reliability through unscheduled flows, which can lead to exceedance of
SOL and transmission limits. For example, WECC membership found it appropriate to apply a limit of 4 times a BA’s
L10. This mechanism provides flexibility to handle interconnection frequency while not allowing ACE deviations to
become so significant that BA flows negatively impact the transmission system. 6) The drafting team stated in their
response to previous comments that “The drafting team will be preparing a report based on the field trial results that will
be posted prior to the FERC filing for this draft standard”. Powerex poses two questions to the drafting team: a) Why
have the field trial results not been provided to NERC membership prior to ballot body? b) Why have the results for the
field trial not been updated on the project page on the NERC website since June 2012? 7) The drafting team has not
adequately addressed the issue of “sawtoothing” operations as exhibited by entities during the field trial. Sawtoothing
can be described as entities that are allowing ACE to be unlimited for 29 minutes and then be brought under BAAL
limits for 1 minute. This type of behavior is shown in the NERC reports posted on the field trial. The drafting team is
hedging that entities will not operate in this manner after the field trial due to higher operation and compliance risk to
entities. However, the NERC field trial should have created disincentives to not allow such behavior during the onset of
the field trial, and requirements should have been adopted to discourage behavior that poses reliability risks.
Individual
Gregory Campoli
NYISO
Northeast Power Coordinating Council
No
The NYISO has concerns based on results of the field trials that were conducted. These field trials have indicated the
potential for an increased number of SOL violations as well as potential for increased ACE due to large inadvertent
flows with the proposed BAAL limits based on frequency triggers. It is not appropriate to indicate the SOL/IROL
Standards will address these additional overloads as the flows that are causing the overloads due to the increase ACE
are not identifiable in any contingency management system. We would propose dropping the BAAL calculation until a
wider field trial could be conducted.
Group
ACES Standards Collaborators
Jason Marshall
ACES
No
(1) How does this standard “specifically preclude general improvements to PRC-005-2”? By introducing a new project
for PRC-005, the entire standard is subject to revision. The previous standard could be modified and there are no
scope restrictions to this project under the NERC Rules of Procedure. There is nothing to preclude changes to
Protection Systems. The drafting team should be aware of these implications and reconsider the development of this
project, as the last draft took almost seven years to gain industry approval. Further, the Commission has not even ruled
on the pending standard, so there is still a tremendous amount of uncertainty as to whether any additional directives or
modifications need to be made to PRC-005-2. (2) We have serious concerns with the new definitions being proposed in
this draft standard. We feel this excessiveness terms are unnecessary when the standard is only adding a new type of
device to an entity’s existing maintenance and testing procedure. (3) For example, the “Auto Reclosing” definition is
vague and requires further interpretation. What does “such as anti-pump and ‘various’ interlock circuits” mean?
“Various” is not a clear adjective to describe interlock circuits. We recommend revising the entire definition to clearly
state the scope of the devices, or better yet, strike the definition from the standard. (4) The term “unresolved
maintenance issue” is plain language with a common meaning, and therefore does not need to be introduced as a
defined glossary term. This definition could lead to more zero defect compliance and enforcement treatment. What
happens if a maintenance issue is not identified as unresolved? Shouldn’t a registered entity’s internal controls address
these issues? Also, this term is missing the other half of the standard – the testing of these devices. It’s possible to
have an unresolved testing issue as well. (5) The Commission set limitations on the autoreclosing devices that should

be included in Order No. 758. An autoreclosing relay should be tested and maintained, “if it either is used [1] in
coordination with a Protection System to achieve or meet system performance requirements established in other
Commission–approved Reliability Standards, or [2] can exacerbate fault conditions when not properly maintained and
coordinated, then excluding the maintenance and testing of these reclosing relays will result in a gap in the
maintenance and testing of relays affecting the reliability of the Bulk-Power System.” This is problematic because the
primary purpose of reclosing relays is to allow more expeditious restoration of lost components of the system, not to
maintain the reliability of the Bulk-Power System. This standard would improperly include many types of reclosing
relays that do not necessarily affect the reliability of the Bulk-Power System. (6) Order No. 758 (P. 26), the Commission
stated that “the standard should be modified, through the Reliability Standards development process, to provide the
Transmission Owner, Generator Owner, and Distribution Provider with the discretion to include in a Protection System
maintenance and testing program only those reclosing relays that the entity identifies as having an affect on the
reliability of the Bulk-Power System.” (7) There are concerns with the supplementary reference document because it
assumes that PRC-005-2 will be approved by the Commission. This assumption is misleading and should not reflect
any Commission rulings that have yet to occur. We recommend stating the current status of the PRC-005-2 project,
which was filed with FERC in February 2013 and is pending the Commission’s approval. Statements such as “PRC005-2 ‘replaced’ PRC-011” should be modified to “PRC-005-2 will replace PRC-011 upon approval from FERC,” or
something similar. (8) The drafting team stated that it reviewed the NERC System Analysis and Modeling
Subcommittee (SAMS) “Considerations for Maintenance and Testing of Autoreclosing Schemes — November 2012.”
SAMS concluded that automatic reclosing is largely implemented throughout the BES as an operating convenience,
and that automatic reclosing mal-performance affects BES reliability only when the reclosing is part of a Special
Protection System, or when inadvertent reclosing near a generating station subjects the generation station to severe
fault stresses. This report is concluding that these devices do not result in a gap and do not affect the reliability of the
Bulk-Power System, unless very specific circumstances arise as in the instance where reclosing relays are a part of an
SPS scheme. This technical document does not support the development of the standard; rather, the report refutes the
need to include these devices in the standard’s applicability.
No
(1) The SDT needs to clarify the implementation plan. The document is confusing because it focuses on the PRC-0052 standard, which is not yet FERC-approved. This implementation plan is a constantly changing moving target. Why
not wait until PRC-005-2 gets approved before initiating another project for the same standard? This would reduce
some of the timing issues and confusion. (2) Why is the drafting team revising a standard that has not been approved
by the Commission yet? The second version was only filed in February 2013, and the timing of this project is
premature. It is quite possible that the Commission could remand or revise parts of the standard and issue other
directives associated with the version 2, which would then need to be addressed. This project is untimely and should
be postponed until there is a final order from FERC. At that point, there may be justification to continue with this project,
expand the scope of the SAR to address any new directives that may be included in a final order of PRC-005-2, or to
determine that a guidance document is an appropriate way to satisfy the FERC orders. (3) The Commission specifically
advised the drafting team of PRC-005-2 to modify the standard to include reclosing relays. Because the drafting team
did not include them during that opportunity, the drafting team should wait until a final order is issued. (4) Again, the
drafting team needs to consider other methods of answering FERC directives. Not every directive needs to be
addressed by developing or revising a standard. Adding reclosing relays to PRC-005 only complicates the mostviolated non-CIP standard. There is enough concern about this standard already and the drafting team should consider
alternative means to address the reclosing relay issue besides a standard revision. (5) This project contains similar
timing issues as CIP version 4 and CIP version 5 because it is being developed prior to FERC issuing a final order on
the previous version of the standard. The timing is problematic; registered entities will be forced to constantly be
focusing on the next standard. The implementation plan should provide additional time, similar to PRC-005-2’s two
intervals, to allow registered entities enough time to adjust their PSMT programs for Protection Systems, and then have
additional time to adjust their PSMT plan and implement autoreclosers. (6) Thank you for the opportunity to comment.
No
Individual
John Bee on Behalf or Exelon and its Affiliates
Exelon

Yes
Exelon is basically fine with structure, but continues to have issues with frequency response measurement process,
which compares current ACE to previous one minute avg. frequency. This creates a situation in which Real Time
adjustments to generation dispatch might actually serve to hamper frequency support, rather than serve it.
Group
Tennessee Valley Authority

Dennis Chastain
Tennessee Valley Authority
Agree
SERC OC Standards Review Group
Group
Oklahoma Gas & Electric
Terri Pyle
Oklahoma Gas & Electric
Yes
No
While we appreciate the attempt to streamline and simplify the standard, the requirement of Balancing Authorities
providing Overlap Regulation Service should be moved back into the requirements section. The Standard should be
enforceable based solely on the Requirements. “The most critical element of a Reliability Standard is the
Requirements. As NERC explains, “the Requirements within a standard define what an entity must do to be compliant .
. . [and] binds an entity to certain obligations of performance under section 215 of the FPA.” If properly drafted, a
Reliability Standard may be enforced in the absence of specified Measures or Levels of Non-Compliance.” (NOPR and
Order 693)
No
Group
Luminant
Brenda Hampton
Luminant Energy Company LLC
Agree
Electric Reliability Council of Texas (ERCOT)
Group
IRC-SRC
Terry Bilke
MISO
No
We don’t understand the reasoning for these new definitions. Balancing Authorities have an Area Control Error. The
standards presently allow for overlap and supplemental regulation that allow a BA to obtain regulation services, which
appears to be the driver for these definitions. We also cannot find in a SAR associated with this project the need to
change the definitions.
Unless there is justification we missed, the new definitions should be removed. With regard to the ACE equation and
the WECC ATEC term, we recommend that the ACE equation be simplified and made such that it would work with any
interconnection. We recommend the term IATEC be changed to ITC, which would stand for Time Control. The
balancing standards should limit the magnitude of TC to a value such as 20% of Bias. This would work for both the
WECC and HQ approach to controlling time error and assisting in inadvertent interchange management (WECC). It
would also give the Eastern Interconnection a tool to reduce the number of Time Error Corrections, which will be
important if we want to encourage generators to reduce their deadbands under BAL-003-1.
Group
BC Hydro and Power Authority
Patricia Robertson
BC Hydro and Power Authority

No
BCHA applauds the significant improvement made in this proposed standard to add the term Reporting ACE and to
create the definition for Regulation Reserve Sharing Group. However, BCHA respectfully submits the following reasons
for its Negative vote: 1.The reliability impacts of increased unscheduled flow have not been adequately addressed. BC
Hydro suggests studying in detail those events where a BA’s ACE was within BAAL however the Reliability Coordinator

still instructed the BAs to reduce ACE within L10 to mitigate path transmission loading issues. 2.There is no
requirement for BAs to maintain their true load-resource balance, i.e. no requirement for ACE to cross zero during any
predetermined scheduling period, or for the averaged ACE over any predetermined scheduling period to be within a
reasonable limit about zero. The “base line” of zero-ACE for a true balance can be moved to as far away as the BAAL
limit without any consequences to the BA as long the scheduled frequency is maintained (by other BAs with ACE in the
opposite sign). Although there is more flexibility for BAs to deploy their resources and some potential benefit gained by
reduced wear and tear cost, BAs may interpret BAAL as their rights to withhold their resource commitment. 3.Increased
difficulties in the planning time frame for transmission use. The basis for setting aside the Transmission Reliability
Margin might have to be revised to account for a wider range of ACE allowed by BAAL. This may lead to a larger
transmission margin being made unavailable for commercial use. 4.Increased needs in real time for the RC to monitor
SOL/IROL overloading and their instruction to BAs to scale back on ACE magnitude. This might be not practical for an
Interconnection with multiple-RCs. It may also raise an inequity issue whereby not all BAs will be asked to refrain from
operating with BAAL at the same time. 5.Potential for increased hidden operating costs to Transmission entities such
as increased transmission losses caused by BAs exchanging their large imbalances without transmission rights.
Individual
Keith Morisette
Tacoma Power
Yes
Tacoma Power does not support the proposed standard. BAL-001 as proposed moves forward with a control standard
that has not yet been fully vetted. Since the RBC field trial began in 2010, with a significant portion of WECC BA
participation, results point to noteworthy reliability and market related issues. As the RBC allows larger BAs looser
control (i.e. larger ACE values) and wider frequency values, the results include: increased coordinated phase shifter
operations, dramatic increase in schedule curtailments due to unscheduled flow, frequency increasing in a negative
direction during heavy load hours and positive direction during light load hours, increased manual time error corrections
and hours of manual time error corrections and increasing inadvertent accumulations. All of these issues need time to
be vetted by the industry and the proposed standard modified accordingly before Tacoma Power would support it.
Tacoma Power does not support a standard that institutionalizes a control methodology that is still in the development
stage and is not supported by actual data. Thank you for consideration of our comments.
Group
Bonneville Power Administration
Jamison Dye
Transmission Reliability Program
No
The definition of Regulation Reserve Sharing Group (RRSG) does not match the Applicability section. The above
definition states that the pooled regulating reserves are used by the member balancing authorities to meet applicable
regulating standards. I don’t think this is technically correct. The balancing authority that is a member of an RRSG
basically transfers its obligations to the RSSG as Responsible Entity. The BA is only the Responsible Entity during
periods where they are not in active status with the RRSG. Suggested rewording: End the sentence after the second
occurrence of “Balancing Authorities” and delete “to use in meeting applicable regulating standards”. This may be
sufficient but would probably be better if the following were added to the end: “When Balancing Authorities which are in
active status and operating under the rules of an RRSG, the RRSG becomes the Responsible Entity for Standard
Requirements related to Regulating Reserves for the member Balancing Authorities.
No
1. The impacts of the field trial have not been analyzed thoroughly enough to put this to a vote at this time. In the
WECC, we have seen an increase in frequency deviations, the number of manual time error corrections, coordinated
phase shifter operations, and unscheduled flow during the period of the field trial. It is not entirely clear to what extent
the Field Trial is responsible for these increases. The data collected has not been made available to the individual
Entities for analysis and evaluation. At the NERC level there is some information posted but it is not in great enough
detail to be able to make a decision on the merits or risks associated with the BAAL standard. One piece of information
which seems blatantly missing is the degree to which participating BA’s have detuned their AGC systems for the field
trial. Without this information it seems an objective analysis of the impacts would be impossible. If we are seeing an
increase in the number of frequency excursions yet the participating BA’s have only minimally (or not at all) detuned
their AGC algorithms then we may unknowingly be sitting on the brink of reliability disaster should the standard pass
and BA’ fully detune their AGC systems to take full advantage of the new requirements. 2. The tools for managing path
flows with respect to larger allowed deviations by participating BAs did not keep up with the RBC pilot. 3. BAL-001 is
driven by economics, not reliability. It is easy to assess the $$$ gains by operating to BAAL, but the additional costs
incurred to your Balancing Authority because of another Balancing Authority's operation within the BAAL envelope is

not easily calculated. Within NERC and in general, a system operating at 60 Hz is more reliable than one operating at
some other value; however, there is no proof that the BAAL operating range is unreliable. Studies must be run on the
WECC system with off-nominal frequency. This has been brought up in study team meetings, but the studies have yet
to be performed. 4. This standard seems to be moving contrary to the general trend of standards development. While
all other standards seem to be aiming for improvements to reliable system operations this standard is going the other
direction by considerably relaxing the Control Performance Standards. It is difficult to understand how a standard which
allows a BA to accumulate extremely large negative ACE – potentially in the minutes just prior to a major MSSC event could possibly be an improvement for reliability. From the control required of CPS2, this appears to be a lowering of the
bar. 5. Any field trial results in addition to the limitations pointed out in 2. Above, are further tainted by the fact that not
all BA’s are participating in the field trial. Only about 2/3rds of the total frequency bias of the Eastern Interconnection is
represented by BA’s in the field trial. In the WECC that percentage is higher but it is known that not all of the
“participating” BA’s have changed their control algorithms and for the BA’s that have; the magnitude of the control
system changes are not known. 6. There are a variety of commercial issues being raised by entities familiar with the
field trial. The issues range from transmission system flows and transmission rights being usurped by unscheduled flow
to issue of imbalances being allowed to go into a BA’s ACE and Inadvertent Interchange balances. 7. Large Balancing
Authorities benefit disproportionately to small Balancing Authorities. Under certain conditions, small Balancing
Authorities may experience a more narrow operating bandwidth under the proposed BAL-001-1 than under the existing
BAL-001. 8. There is no averaging of ACE, other than the one minute average used in the metric. This allows large
deviations in ACE for prolonged periods of time, up to 29 minutes, without any adverse consequences to the BA with
respect to this standard. 9. At this point in time BPA sees no simple solution to these issues. More information needs to
be collected from Balancing Authorities taking part in the field trial and that information needs to be made more
available to all interested parties. More extensive analysis needs to be done before any informed decisions can be
made on this dramatic change to the control performance standards. 10 BPA believes that the analysis done during the
field trials have been conducted with incomplete information, most notably they are lacking information on exactly what
changes, if any, participating BA's have made to their control systems. 11 BPA believes that the proposed standard
reduces the control performance measures by allowing "looser" control and is therefore, less stringent than the current
standard, It is hard to understand how a loosening of the control performance standards can provide an increase in
reliability.
No
Individual
Alice Ireland
Xcel Energy
Yes

Yes
1) The implementation plan does not include any mention of the WECC Automatic Time Error Correction in the
definition of Reporting ACE. This deficiency needs corrected as was done in the BAL-001-2 document. Xcel Energy
believes the drafting team provided the correct definition in the BAL-001-2 document and therefore this should not be a
significant change to the implementation plan or standard. 2) Additionally, it is not clear how a minute that has bad data
should be treated in the determination of a 30 minute period under BAAL. This issue needs to be clarified, especially if
the minute with bad data happens to be the first or last minute. Xcel Energy is not asking for a change to the standard,
just a clear statement for the purposes of documenting compliance.

Name (32 Responses)
Organization (32 Responses)
Group Name (23 Responses)
Lead Contact (23 Responses)
Contact Organization (23 Responses)
IF YOU WISH TO EXPRESS SUPPORT FOR ANOTHER ENTITY'S COMMENTS WITHOUT
ENTERING ANY ADDITIONAL COMMENTS, YOU MAY DO SO HERE. (13 Responses)
Comments (55 Responses)
Question 1 (35 Responses)
Question 1 Comments (42 Responses)
Question 2 (36 Responses)
Question 2 Comments (42 Responses)
Question 3 (36 Responses)
Question 3 Comments (42 Responses)
Question 4 (35 Responses)
Question 4 Comments (42 Responses)
Question 5 (37 Responses)
Question 5 Comments (42 Responses)
Question 6 (32 Responses)
Question 6 Comments (42 Responses)
Question 7 (34 Responses)
Question 7 Comments (42 Responses)
Question 8 (32 Responses)
Question 8 Comments (42 Responses)
Question 9 (33 Responses)
Question 9 Comments (42 Responses)
Question 10 (0 Responses)
Question 10 Comments (42 Responses)

Individual
Ken Gardner
Alberta Electric System Operator

No
Please consider revising requirement R2 to use the proposed new definitions as follows: R2. Except
during the Contingency Event Recovery Period and Contingency Reserve Restoration Period, or during
an Energy Emergency Alert Level 2 or 3, each Responsible Entity shall maintain an amount of
Contingency Reserve at least equal to its Most Severe Single Contingency. [Violation Risk Factor:
Medium] [Time Horizon: Real-time Operations]

Individual
Tom Siegrist
EnerVision, Inc.
Yes

Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes

Group
Northeast Power Coodinating Council
Guy Zito
Northeast Power Coordinating System
Yes
No
The last sentence in the definition is not needed, and should be removed. “The capacity may be
provided by resources such as Demand Side Management (DSM), Interruptible Load and unloaded
generation.” is the “How” to meet the contingency reserve requirement, which does not belong in a
definition. Suggest to remove this sentence.
No
There is no need to define the term Reserve Sharing Group Reporting ACE. This term is not
referenced or used in the Standard at all. If the RSG is obligated to meet the DCS requirement and
needs to return its ACE to zero or the Pre-Reportable Contingency Event value, then the Standard is
not explicit nor complete enough to place this obligation on the RSG.
Yes
Yes
Yes
Yes
Yes
Yes
There isn’t an appropriate technical justification for requiring a 500 MW threshold. If the justification
is simply to obtain more data samples, a 1600 data request is more appropriate than an enforceable
Standard. Suggest reverting back to the 80% threshold which has thus far, shown to provide for an

adequate level of reliability. The Standard can be simplified by replacing the existing requirements
with ones that read: • recover from a Reportable Event within 15 minutes; • replenish reserves within
90 minutes.
Group
Arizona Public Service Company
Janet Smith, Regulatory Affairs Supervisor
Arizona Public Service Company
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes

Individual
John Tolo
Tucson Electric Power
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
very helpful

Individual
Rich Hydzik
Avista
No
The changes to the definitions add clarity, but ambiguity still exists around one phrase. What
constitutes an “unexpected change to the responsible entity’s ACE?” Does this mean that there is no
human action when the ACE change occurs? Does this mean that a human action to change a Net
Interchange value in the ACE equation is “unexpected” when it is due some force majeure condition?
Clarity around this issue is necessary to prevent Balancing Authorities (BA) from merely adjusting
their Net Schedule Interchange value to correct ACE and passing the problem on to another BA. If
transmission curtailments and unexpected adjustments to e-tags are acceptable events to deploy
contingency reserve and are considered “Sudden Loss of Generation” under BAL-002-2, this needs to
be explicitly stated. If transmission curtailments and unexpected adjustments to e-tags are NOT
acceptable events to deploy contingency reserve and are NOT considered “Sudden Loss of
Generation” under BAL-002-2, this needs to be explicitly stated. The Background Document discusses
frequency deviations on Page 4 under “Balancing Contingency Event.” This seems to preclude any
human action to alter Net Scheduled Interchange as a “Balancing Contingency Event.”
Yes
Yes
The assumption is made that algebraic sum of the ACE’s is as follows: Reserve Sharing Group
Reporting ACE = ACE(BA1) + ACE(BA2) + ACE(BA3) + …. An example calculation would be helpful
and provide clarity.
Yes
This language clarifies that when in an Energy Alert 2 or 3, the BA is using all available reserves to
maintain ACE.
Yes
Yes
Yes
Yes
Yes
I can support this draft standard with the clarifications requested in Question #1 above.
Individual
Nazra Gladu
Manitoba Hydro
Yes
No comment.
Yes
No comment.
Yes
No comment.
Yes
No comment.

Yes
No comment.
Yes
No comment.
Yes
No comment.
Yes
No comment.
Yes
No comment.
Although Manitoba Hydro is in support of this standard, we have the following clarifying comments:
(1) Definitions, Reportable Balancing Contingency Event – there is no definition within the standard or
Glossary as to what ‘EMS scan rate data’ is. (2) Definitions, Contingency Event Recovery Period – the
definition does not clearly define exactly when the Contingency Event Recovery Period begins. As
written, the definition seems to indicate that this period begins at two different times (i) when the
resource output begins to decline and (ii) in the first one minute interval of a Balancing Contingency
Event. Please clarify. (3) Section D, Compliance, 1.1 – the paraphrased definition of ‘Compliance
Enforcement Authority’ from the Rules of Procedure is not the standard language for this section. Is
there a reason that the standard CEA language is not being used? (4) 1. (Proposed) Effective Date in
both Standard and Implementation Plan - remove the “ ‘ “ following the word ‘Trustees’ because it is
not defined this way in the Glossary of Terms. (5) R1 - as written, R1 requires that the Responsible
Entity demonstrate that ACE was returned to a certain value. The demonstrate aspect of the
requirement seems more of a measure than a requirement. In other words, the requirement should
be that the Responsible Entity return the ACE to a certain value, the measure is that they provide
evidence to demonstrate that they did so. (6) R1, R2 – both ‘MSSC’ and ‘Most Severe Single
Contingency (MSSC)’ are used throughout the standard. The words ‘Most Severe Single Contingency
(MSSC)’ should be used at the first instance and then the acronym ‘MSSC’ for all instances thereafter.
(7) R2 – some of the terminology appears to be incorrect within this requirement. Is ‘Disturbance
Recovery Period’ meant to be ‘Contingency Event Recovery Period’? Is ‘Contingency Reserve Recovery
Period’ meant to be ‘Contingency Reserve Restoration Period’? (8) M1 – the word ‘including’ should be
replaced with ‘as well as’ if the ‘additional documentation’ that needs to be provided is in addition to
the CR Form 1, not that the additional documentation forms part of the CR Form 1. (9) VRF/VSL capitalize ‘bulk electric system’ in both the High Risk Requirement and Medium Risk Requirement
sections. (10) VSL, R1 – the language of the VSL does not track the language of the requirement or
measure. The VSL refers to ‘recovering from an event’ while the requirement refers to returning ACE
to a certain level. (11) VSL, R2 – the language of the VSL does not track the language of the
requirement or measure. The VSL refers to calendar quarters, while the requirement and measure do
not.
Group
Salt River Project
Bob Steiger
Electric Reliability Compliance
Yes
Yes
This standard is a big improvement over the existing standard because it provides much needed
formal definitions of many terms that are used but not currently defined in BAL-002-1, the definition
of Contingency Event, Contingency Reserve and MSSC being three of them.
Yes
Same comment as for #2.
Yes

Yes
Yes
Yes
Yes
Yes

Group
PacifiCorp
Ryan Millard
PacifiCorp
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes

Individual
Rich Salgo
NV Energy
No
Inclusion of “Sudden loss of a known load” is at odds with the Contingency Reserve definition,
especially in light of the fact that loss of load cause ACE to increase (become more positive). In other
words, why would one carry reserves to handle a decrease in load? It’s illogical. What the SDT may
be trying to reference is the use of interruptible load as a type or reserve. As such, load should not be
in the Contingency Event definition.
Yes
Yes

Yes
Yes
Yes
Yes
Yes
Yes
The Reportable Balancing Contingency Event definition lacks clarity. Are we to choose the higher of
500 MW vs. 80% of the MSSC or the lower of 500 MW vs. 80% of the MSSC? Seems like the
measurement should be the higher of the two. 2. While I think I understand the goal of R1, to return
ACE to zero neglecting other contingency events within the recovery period, the wording is very
confusing. Expect misapplication of the standard with the existing wording. I suggest, for bullet #2: •
Its Pre-Reportable Contingency Event ACE, (if its Pre-Reportable Contingency Event ACE was
negative), o less the Balancing Contingency Events’ magnitude summation for all subsequent events
occurring within the Contingency Event Recovery Period, and o If the contingency event is greater
than MSSC, further reduce the ACE recovery magnitude by difference between the Responsible
Entity’s MSSC and the uncompleted Balancing Contingency Events’ magnitude summation.
Group
MRO NERC Standards Review Forum
Russel Mountjoy-Secretary
MRO

No
The presently approved NERC definition for contingency seems adequate for this standard. If the DCS
definition will not be used any longer, recommend the team retire it from the NERC glossary.
Yes
No
All that’s needed is a simple statement in the applicability section that the standard does not apply to
BAs when they are in EEA 2 or 3.
No
This requirement will have significant negative unintended consequences. Reserves are an inventory
intended to be used when there is a reliability need. The first unintended consequence is that BAs are
encouraged by this requirement never to deploy their contingency reserves except for a DCSreportable events. The original Policy 1 noted many reasons for operating reserves. BAs whose ACE is
extremely negative for other reasons would be reluctant to deploy their contingency reserves because
the timer would start ticking on the “available hours” clock. Please clarify. The second unintended
consequence for those BAs that don’t withhold contingency reserves for non-DCS events is that they
will be obliged to increase the amount of contingencies the carry so they always have more reserves
than their MSSC. This will increase costs to our customers without a demonstrated need. DCS
performance in North America has been stellar compared to what was considered adequate
performance under Policy 1. Please clarify. The last most significant unintended consequence relates
to the embedded expectation to recover from and measure multi-contingent events beyond MSSC.
When these events happen, something bigger is going on. Transmission security is probably an issue.
Forcing a knee-jerk expectation to drive ACE back toward zero during a major event will likely do
more harm than good. This is another thing that wasn’t in the drafting team’s SAR or in a directive.
Events greater than MSSC should be reported, but not evaluated for compliance. While it’s fine to

embed some of the calculations in the background document in a reporting form, events greater than
MSSC should be excluded from compliance evaluation. This proposal sets a commodity standard
which is not in keeping with the superior approach of having performance-based standards. Not all
BAs have the same needs for the various types of operating reserves. Performance is the
demonstration of adequacy. Is the SDT stating that recovery is needed to recover to zero or MSSC?
We believe the way a way to achieve the Commissions directive for a continent wide policy is for the
drafting team, in concert with the NERC operating committee, to create a policy document that
outlines the factors that the BA uses in performing an assessment of needed frequency responsive,
regulating and contingency reserves. The policy should provide simple definitions for frequency
responsive, regulating, contingency, and replacement reserves. Once the policy has undergone
comment through the standards process (this was the directive in 693), NERC should add these four
types of reserves to “Attachment 1-TOP-005 Electric System Reliability Data” with the expectation in
the policy that Reliability Coordinators collect this information in real time for use in the EEA process.
No
We believe the requirement itself is inappropriate, so any VRF is unnecessary.
Yes
No
Requirement 1 should not be an event by event obligation. A quarterly measure has worked quite
well. We disagree with the current R2 so we cannot offer a suggestion to improve its VSL.
No
There first needs to be agreement on the requirements before there is concurrence with the
background document.
Besides the concerns presented above, we are troubled with the significant changes that will occur
within R1 compared to today’s DCS and the fact that the drafting team is asking no questions about
those changes. The current DCS is measured on a quarterly basis. The way the proposed requirement
1 and VSL are crafted, this is now an event by event compliance evaluation. When you add the fact
that the team is also embedding a 500 MW reporting threshold and the multi-contingent event
expectation, this exposes the industry to a heavy-handed standard for no reliability need. It should be
noted that DCS performance has been stellar across North America compared to what existed under
Policy 1. The changes being implemented are well beyond what was in the drafting team’s SAR and
the Order No. 693 directives. Recommend that each interconnection has a different MW level, due to
the sheer size of each interconnection. As an Eastern Interconnection entity, we recommend 900 MW
vise 500 MWs. The SAR for the drafting team was basically to clean up the V0 clutter in the standard
and address Order No 693 directives. The only two true requirements in the V0 standard are to
recover from reportable events in 15 minutes and replenish reserves within 90 minutes. These should
be the basis of BAL-002-1. Our recommendations are: • Preserve the two true requirements today
(recover from reportable events within 15 minutes and replenish reserves in 90 minutes). • Provide
clarity in the compliance section of the standard or the background document how events > MSSC are
reported. Note: We believe it is acceptable to put something in the compliance section of the standard
that notes if the same event > than MSSC occurs within 3 years, the BA should be held to the DCS for
that contingency. • Due to concerns we have in BAL-013, we believe the reporting form for BAL-002
should also have a reporting slot for large loss of load events (Order No. 693 directive), but for
reasons we state in BAL-013, believe that these should be excluded from compliance evaluation. •
The continent-wide contingency reserve policy should be a separate guidance document under the
purview of the NERC Operating Committee with comments collected under the standards process
along with this standard. This meets the 693 directive. The policy document should provide guidance
on how the BA should assess the necessary amount of reserves as well as provide simple definitions
of the different types of reserves. Once these terms are defined and commented on by the Industry in
the policy, NERC should add these four types of reserves to “Attachment 1-TOP-005 Electric System
Reliability Data” with the expectation in the policy that Reliability Coordinators collect this information
in real time for use in the EEA process. The policy could ask the BAs to initially review and assess
their needs and relay this to their RC. The policy would be available for re-review if the BA’s
performance approaches non-compliance. The standard should be based on the lesser of 80% of
MSSC, 1000MW, or a lower value chosen by the Balancing Authority. The drafting team is proposing
to continue to use only ACE under Requirement R1 as the measure of reliability in the determination

of Balancing Authority or RSG compliance. As has been seen in actual operation, the current
methodology can lead to and has caused RC directives to drop load when there was not a reliability
issue, defined as a frequency concern or transmission line loading issue. ACE is not a primary
measure of reliability, only equity. To remedy this deficiency in the proposed standard, the drafting
team should utilize the BAAL limit as a more appropriate measure of response to the sudden loss of
generation, not pre-event ACE or zero, whichever is lower. As proposed by the NSRF, this does not do
away with DCS as originally proposed under BAAL but would change the measure of compliance in the
DCS process to a more appropriate, reliability based measure. The NSRF is also not proposing to
change the 15-minute period in BAL-002 for a reportable event with this modification.
Individual
Anthony Jablonski
ReliabilityFirst

No
a. ReliabilityFirst recommends removing any references to “an Energy Emergency Alert Level 2 or
Level 3” since these are not defined terms (Energy Emergency Alert Levels are only noted in
Attachment 1, EOP-002-3). ReliabilityFirst believes the BAL-002-2 should stand on its own merit and
not rely on conditions within an attachment within another standard. For example, if the Energy
Emergency Alert levels designations ever change in the future, this has the potential to have an
impact on the intent of the BAL-002-2 standard. For consideration, ReliabilityFirst recommends
defining the alert levels within the standard itself as an attachment, hence not relying on another
standard for these conditions.

No
The VSLs for Requirement R2 references “each calendar quarter” while the actual requirement R2
does not require maintaining an amount of Contingency Reserve at least equal to its Most Severe
Single Contingency on a quarterly basis. Also, the lower VSL starts with an entity being deficient for
more than five hours. This poses a gap; if for example, an entity was deficient between one and four
hours. ReliabilityFirst recommends restructuring the VSLs, to be consistent with the language in the
requirement, as follows (this is an example of a Lower VSL); “The Responsible Entity maintain an
amount of Contingency Reserve at least equal to its Most Severe Single Contingency but its
Contingency Reserve was deficient for less than or equal to 15 hours.”
ReliabilityFirst votes in the negative for this standards and offers the following for consideration: 1.
Definition of Reportable Balancing Contingency Event: ReliabilityFirst does not agree with the
inclusion of last sentence (i.e., The 80% threshold may be reduced upon written notification to the
Regional Entity) within the definition. As written, the definition infers that there is an expectation that
a Regional Entity may have to make a determination on whether to accept a reduction in the 80%
threshold based upon the written notification. This is troublesome in two ways. One, this is written
more like a requirement, though it is actually contained within a definition. Two, standards should not
be written with expectation placed upon a non-registered entity (i.e., the Regional Entity).
ReliabilityFirst recommends removing this last sentence and any reference to the Regional Entity. 2.
Applicability Section - ReliabilityFirst recommends removing the paragraph stating “Applicability is
determined on an individual event basis…” from the Applicability section. The Applicability section
should state the functional entity that is required to comply with the standard and the requirements
should state any conditions necessary to achieve the action or outcome.
Individual
Joe Tarantino
SMUD

Yes
Yes
Yes
Yes
Yes

Individual
Jim Cyrulewski
JDRJC Associates LLC
Agree
Midwest ISO
Group
SPP Standards Review Group
Robert Rhodes
Southwest Power Pool
No
We would suggest incorporating the concept of an unexpected event with the loss itself rather than
tying it to the change in ACE. For example in Subsection A, we would propose: ‘Sudden, unexpected
loss of generation…’ Similar changes need to be made to Subsections B and C. Also, there is a timing
element associated with Subsection B which could cause conflict with the wording in B. Requiring a
sudden loss of import by the loss of a transmission element, implies that the loss of import would be
sudden. It may or may not be. It depends on when the loss is reflected in schedules. Additionally, an
entity may not know that the loss is due to a loss of transmission. We would suggest: ‘Sudden,
unexpected loss of an import that causes a change to the responsible entity’s ACE.’ In Subsection C
we suggest: ‘Sudden unexpected loss of a known load…’ The term ‘responsible entity’ is not
capitalized in the definition but is in the standard. Should it be in the definition?
No
As written there is no distinction as to whether ‘unloaded generation’ is on-line or off-line generation.
Which is it, or is it both? Additional clarification here would be helpful.
No
Do you need to add ‘…at the time of the measurement’ at the end of the definition?
Yes
Yes
Yes
Yes

No
Change all of the R1 VSLs to read ‘The Responsible Entity partially recovered…’
No
We offer the following suggestions: Page 3 1st paragraph 2nd line – replace ‘They’ with ‘It’ 4th line –
remove the hyphen in ’15-minute’ 2nd paragraph 1st line – remove space following ‘Policy’ and insert
space after the period Page 4 1st paragraph under Contingency Reserve 2nd line – replace ‘its’ with
‘their’ 6th & 7th lines – be consistent with the hyphens in demand side management Page 5 Correct
the text formatting for Requirement 1 Page 6 2nd paragraph Capitalize Contingency Reserve 3rd
paragraph 1st line – delete space in R1 5th paragraph Reword the 2nd sentence to read: ‘Reviewing
the data, the drafting team decided to establish a single, continent-wide standard on the median
value of generation loss.’ Under Violation Severity Levels This needs to be rewritten. The VSLs are
based solely on amount of recovery. The paragraph tries to include the sufficiency of response but it’s
not in the VSLs. Page 10 Last paragraph Needs to be rewritten; what’s there refers to R1 not R2.
Individual
Greg Travis
Idaho Power Company
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes

Individual
Michael Falvo
Independent Electricity System Operator
Yes
No
We generally agree with the revised definition, but do not see the need for the last sentence: “The
capacity may be provided by resources such as Demand Side Management (DSM), Interruptible Load
and unloaded generation.” This is the “How’s” to meet the contingency reserve requirement, which
does not belong to a definition. We suggest to remove this sentence.
No
We do not see the need to define the term Reserve Sharing Group Reporting ACE. This term is not

referenced or used in the standard at all. On the other hand, if the RSG is obligated to meet the DCS
requirement and needs to return its ACE to zero or the Pre-Reportable Contingency Event value, then
the standard is not explicit or complete to place this obligation on the RSG.
Yes
Yes
Yes
Yes
Yes
Yes
We will support this standard, however please note the concerns expressed under Q2 and Q3, above,
namely: a. The last sentence in the definition for Contingency Reserve, and b. The need to define the
term Reserve Sharing Group Reporting ACE (or the lack of explicit requirement for RSG to meet the
DCS requirement).
Individual
Howard F. Illian
Energy Mark, Inc.
No
The term "ACE" should be replaced by the term "Reportable ACE" wherever it is used in this
definition. "ACE" is not adequately defined while "Reportable ACE" is.
Yes
No
The term "ACE" should be replaced by the term "Reportable ACE" wherever it is used in this
definition. "ACE" is not adequately defined while "Reportable ACE" is.
Yes
No
I believe that this requirement falls under Paragraph 81 and should not be in the standard.
Yes
Yes
Yes
Yes
The definition of "Pre-reportable Contingency Event ACE Value" should be modified as follows: The
term "ACE" should be replaced by the term "Reportable ACE" wherever it is used in this definition.
"ACE" is not adequately defined while "Reportable ACE" is. I would strongly suggest that the wording
for Requirement 1 should be modified to read as follows: R1. Except when an Energy Emergency Alert
Level 2 or Level 3 is in effect, the Responsible Entity experiencing a Reportable Balancing Contingency
Event shall demonstrate that within the Contingency Event Recovery Period the Responsible Entity
returned its Reportable ACE to: [Violation Risk Factor: Medium][Time Horizon: Real-time Operations]
x Zero, (if its Pre-Reportable Contingency Event ACE Value was positive or equal to zero): o less the

sum of the magnitudes of all subsequent Balancing Contingency Events that occur prior to that value
of Reportable ACE within the Contingency Event Recovery Period, and o Further reduced by the
magnitude of the difference between (i) the Responsible Entity’s Most Severe Single Contingency
(MSSC) and (ii) the sum of the magnitudes of the Reportable Balancing Contingency Event and all
previous Balancing Contingency Events that have not completed their Contingency Event Restoration
Period when the sum referenced in clause (ii) of this bullet is greater than MSSC, Or, x Its
Pre-Reportable Contingency Event ACE Value, (if its Pre-Reportable Contingency Event ACE Value was
negative), o less the sum of the magnitudes of all subsequent Balancing Contingency Events that
occur prior to that value of Reportable ACE within the Contingency Event Recovery Period, and o
Further reduced by the magnitude of the difference between (i) the Responsible Entity’s Most Severe
Single Contingency (MSSC) and (ii) the sum of the magnitudes of the Reportable Balancing
Contingency Event and all previous Balancing Contingency Events that have not completed their
Contingency Event Restoration Period when the sum referenced in clause (ii) of this bullet is greater
than MSSC.
Group
SERC OC Standards Review Group
Stuart Goza
Tennessee Valley Authority
Yes
Yes
No
The definition should only include the BAs that were participating in the event.
Yes
No
This requirement will have significant negative unintended consequences. Reserves are an inventory
intended to be used when there is a reliability need. The first unintended consequence is that BAs are
encouraged by this requirement never to deploy their contingency reserves except for DCS-reportable
events. The original Policy 1 noted many reasons for operating reserves. BAs whose ACE is extremely
negative for other reasons would be reluctant to deploy their contingency reserves because the timer
would start ticking on the “available hours” clock. The second unintended consequence for those BAs
that don’t withhold contingency reserves for non-DCS events is that they will be obliged to increase
the amount of contingency reserves they carry so they always have more reserves than their MSSC.
This will increase costs to our customers without a demonstrated need. DCS performance in North
America has been stellar compared to what was considered adequate performance under Policy 1. Not
all BAs have the same needs for the various types of operating reserves. Performance is the
demonstration of adequacy. We believe a way to achieve the Commissions directive for a continent
wide policy is for the drafting team, in concert with the NERC operating committee, to create a policy
document that outlines the factors that the BA uses in performing an assessment of needed frequency
responsive, regulating and contingency reserves. The policy should provide simple definitions for
frequency responsive, regulating, contingency, and replacement reserves. Once the policy has
undergone comment through the standards process (this was the directive in 693), NERC should add
these four types of reserves to “Attachment 1-TOP-005 Electric System Reliability Data” with the
expectation in the policy that Reliability Coordinators collect this information in real time for use in the
EEA process. We agree with the principle of a BA maintaining contingency reserves to respond to its
MSSC. However, as R2 is currently proposed it puts the BA at risk if contingency reserves fall below
its MSSC for any single sampling period. Indeed, as stated it puts a BA with a 2 second sampling
interval at greater risk than a BA with a 6 second sampling interval. While the SDT has attempted to
resolve this issue in the Measures and VSL, we believe that the requirement needs to stand on its own
and that the specifying language should be included in R2 itself.
No

It is difficult to agree with the VRF’s while disagreeing with the standard as proposed.
Yes
No
Requirement 1 should not be an event by event obligation. A quarterly average measure has worked
quite well. We disagree with the current R2 so we cannot offer a suggestion to improve its VSL.
No
The Background Document states on page 4 that “FERC Order 693 (at P355) directed entities to
include a Requirement that measures response for any event or contingency that causes a frequency
deviation.” We disagree with this interpretation of the Commission’s directive. In Order 693 (P355)
the Commission declined to define a ‘significant deviation as a frequency deviation of 20 mHz’, but
instead directed the ERO ‘to define a significant deviation and a reportable event’. The Commission
directed that ‘loss of supply, loss of load and significant scheduling problems, which can cause
frequency disturbances,’ must be taken into account when developing the aforementioned definitions.
We believe that the Commission clearly did not intend that any event that causes a frequency
deviation, not matter how small, be included in DCS reporting, but rather that a significant frequency
deviation be defined by the ERO. The definition of a Reportable Balancing Contingency Event should,
but currently does not, reflect such a definition. The Background Document on page 6 points to
statistical frequency data supplied by CERTS in Attachment 1 to support the 500 MW reporting
threshold. While Attachment 1 shows the box plots used for this determination, it does not provide a
narrative defining the sampling data or method. It appears that frequency deviations resulting from
loss of load and loss of supply were included in the same data sample. We question whether this is
appropriate and believe that in order for the industry to effectively evaluate the proposed criteria, a
narrative needs to be added to Attachment 1 that explains the data sample and method. We suggest
that additional details be provided in the Background Document relating to the methodology for
development of the reporting thresholds.
There is an embedded expectation to recover from and measure multi-contingent events beyond
MSSC. When these events happen, something bigger is going on. Transmission security is probably an
issue. Forcing a knee-jerk expectation to drive ACE back toward zero during a major event will likely
do more harm than good. This is another thing that wasn’t in the drafting team’s SAR or in a
directive. Events greater than MSSC should be reported, but not evaluated for compliance. While it’s
fine to embed some of the calculations in the background document in a reporting form, events
greater than MSSC should be excluded from compliance evaluation. We appreciate the SDT’s goal of
drafting a continent-wide standard but disagree with the SDT’s approach of ‘one size fits all’ in
defining a Reportable Balancing Contingency Event. As previously stated, we believe that the
Commission directive of defining a significant (frequency) event is not satisfied by this standard.
Additionally, using 500 MW as an example, a loss of 500 MW may cause a significant frequency
deviation at midnight on April 1st but not at 17:00 on August 1st. The same 500 MW loss may cause
a significant frequency deviation in the Western Interconnection but not in the Eastern
Interconnection. We believe that this SDT and other SDT’s have acknowledged that a ‘one size fits all’
approach is not always appropriate for all Interconnections. In the proposed BAL-001-2, the BARC
SDT proposes a definition of ACE that is only applicable for the Western Interconnection. In BAL-0031, that was recently approved by the industry and the NERC BOT, the FR SDT identified different
frequency excursion criteria for each Interconnection that are used to identify candidate events for
evaluating frequency response performance. The FRI Report, approved by the NERC PC and accepted
by the NERC OC, identified different statistically derived delta frequencies for each Interconnection in
developing IFRO’s. The State of Reliability Report prepared by the NERC identifies “the triggers for
significant frequency events” that are specific to each Interconnection. We respectfully suggest that
the SDT give due consideration to redefining a Balancing Contingency Event and Reportable Balancing
Contingency Event that satisfies the Commission directive of defining a significant (frequency)
deviation. Such a definition could resemble 80% of MSSC or a supply, load, or scheduling event that
results in a frequency deviation of XXmHz (depending on the Interconnection) in any rolling XX
second period. Previous work completed by the FR SDT and NERC staff could be leveraged to this
end. We believe this is one approach that could satisfy the directive set forth in Order 693. In R1 and
R2, delete the language related to an RE under an Energy Emergency Alert Level 2 or Level 3, for 2
reasons: (1) An EEA in effect for any BA or RSG other than the RE experiencing the contingency
should not give the RE an exemption from R1. E.g. an EEA in effect for a BA in Florida should not be a

consideration for the performance of a contingent RE anywhere in the EI. The language makes the
assumption that both the EEA and contingency are affecting a single, specific RE – this is probably
what the SDT intended but the language used in R1 and R2 is too generic. (2) The “Applicability”
section clearly states that the standard does not apply to an RE under an EEA. Words could be added
to R1 and R2 to clarify that the contingent RE is also the RE experiencing an EEA but a better solution
is to simply delete the EEA related language from R1 and R2, Would it be sufficient for the RE to
restore ACE to within the dynamic BAAL limits instead of the “hard” criteria of zero or pre-contingent
ACE value within the 15 minute recovery period? Once an RE has gotten ACE within the BAAL limit it
is no longer burdening the interconnection – wouldn’t this be a sufficient recovery? There should be
coordination of the recovery required under BAL-002 with performance under the BAL-001(BAAL)
standard. We suggest that a successful response by the RE would return ACE to the lesser of 0 or its
real time BAAL low limit (if its Pre-Reportable Contingency Event ACE was positive or equal to zero)
and similarly – ACE returned to the lesser of its Pre-Reportable Contingency ACE Value or BAAL low
limit (if its Pre-Reportable Contingency Event ACE was negative). If the interconnection frequency is
high – why require a BA to increase generation more than is necessary to meet its BAAL low limit? If
interconnection frequency is low, the BAAL low limit as well as the zero or pre-contingent ACE rule
would still apply. These comments were also supporteed by Ron Carlsen with Southern Company. The
comments expressed herein represent a consensus of the views of the above named members of the
SERC OC Standards Review Group only and should not be construed as the position of the SERC
Reliability Corporation, or its board or its officers.
Group
seattle city light
paul haase
seattle city light
No
Seattle City Light considers the definition of Balancing Contingency Event proposed in this draft of
BAL-002-2 to be incomplete in that it does not recognize the failure of a unit to start as an “event.”
Seattle recommends revising the definition to read: “A.a.i. Unit Tripping or failure to start at the
scheduled time."
Yes
Yes
Note there are differing reference to Regulating Reserve Sharing Group and Reserve Sharing Group
BAL-001-2 and BAL-002-2. Seattle City Light recommends consistent terminology across the
standards.
Yes
This standard is an improvement over the existing BAL-002 because it clarifies the requirements for a
Balancing Authority or Reserve Sharing Group regarding Contingency Reserve requirements during
Energy Emergency Alerts.
No
Seattle City Light finds Requirement R2 and Measure M2 to lack specificity as to what level of
performance is required for compliance, and recommends the following changes: “R2. Each
Responsible Entity shall maintain an amount of Contingency Reserve such that its clock-minute
average of Contingency Reserves is equal or greater than the Most Severe Single Contingency except
during the Disturbance Recovery Period and Contingency Reserve Recovery Period, or during an
Energy Emergency Alert 2 or 3.” “M2. Each Balancing Authority shall provide evidence, upon request,
such as dated calculation output from spreadsheets, Energy Management System logs, software
programs, or other evidence (either hard copy or electronic format) to demonstrate compliance with
Requirement R2.”
Yes
Yes

Yes
Seattle City Light supports the general concepts of this draft of BAL-002-2, but as with BAL-001-2,
Seattle thinks this draft needs more work and should not be implemented as currently written. It
appears to have been rushed. Several specific recommendations for changes have been noted above.
However, at least until the Guidelines document is available that details how this Standard will work
in conjunction with other BAL Standards, Seattle cannot support this draft.
Individual
Kenneth A Goldsmith
Alliant Energy
Agree
MRO NSRF
Group
PJM Interconnection, LLC
Stephanie Monzon
Stephanie Monzon
Yes
Yes
No
The definition should only include the BA’s participating in the event.
No
PJM agrees with the principle of a BA maintaining contingency reserves to respond to its MSSC but
believe this requirement would have negative unintended consequences. Reserves should be used
when there is a reliability need that may or may not be caused by the loss of a resource. This
requirement encourages BA’s to withhold deployment of contingency reserves except for DCS
reportable disturbances. For example, if a BA’s ACE is dragging into the top of the hour, along with
Interconnection frequency, due to schedule changes and slow unit response, this requirement
incentivizes the BA to withhold deploying reserves. If a BA is approaching an IROL that could be
mitigated by deploying contingency reserves, this requirement penalizes the BA for doing so, even
though the result would benefit the Interconnection. Even if PJM agreed with the proposed R2, which
we do not, as written it puts the BA at risk if contingency reserves fall below its MSSC for any single
sampling period. Indeed, as stated it puts a BA with a 2 second sampling interval at greater risk than
a BA with a 6 second sampling interval. While the SDT has attempted to resolve this issue in the
Measures, specifically M2, PJM believes that the requirement needs to stand on its own and that the
specifying language should be included in R2 itself. DCS performance in North America has been
greatly improved compared to what was considered adequate performance under Policy 1. Not all BAs
have the same needs for the various types of operating reserves. Performance is the demonstration of
adequacy. We believe a way to achieve the Commission’s directive for a continent wide policy is for
the drafting team, in concert with the NERC operating committee, to create a policy document that
outlines the factors that the BA uses in performing an assessment of needed frequency responsive,
regulating and contingency reserves. The policy should provide simple definitions for frequency
responsive, regulating, contingency, and replacement reserves. Once the policy has undergone
comment through the standards process, as was a directive in 693), NERC could add these four types
of reserves to “Attachment 1-TOP-005 Electric System Reliability Data”.
Yes
No

It is difficult to agree with the VSL’s while disagreeing with the standard as proposed.
No
The Background Document states on page 4 that “FERC Order 693 (at P355) directed entities to
include a Requirement that measures response for any event or contingency that causes a frequency
deviation.” PJM disagrees with this interpretation of the Commission’s directive. In Order 693 (P355)
the Commission declined to define a ‘significant deviation as a frequency deviation of 20 mHz’, but
instead directed the ERO ‘to define a significant deviation and a reportable event’. The Commission
directed that ‘loss of supply, loss of load and significant scheduling problems, which can cause
frequency disturbances,’ must be taken into account when developing the aforementioned definitions.
PJM believes that the Commission clearly did not intend that any event that causes a frequency
deviation, not matter how small, be included in DCS reporting, but rather that a significant frequency
deviation be defined by the ERO. The definition of a Reportable Balancing Contingency Event should,
but currently does not, reflect such a definition. The Background Document on page 6 points to
statistical frequency data supplied by CERTS in Attachment 1 to support the 500MW reporting
threshold. While Attachment 1 shows the box plots used for this determination, it does not provide a
narrative defining the sampling data or method. It appears that frequency deviations resulting from
loss of load and loss of supply were included in the same data sample, skewing the results. PJM
believes that in order for the industry to effectively evaluate the proposed criteria, a narrative needs
to be added to Attachment 1 that explains the data sample and method.
In R1 and R2, delete the language related to a Responsible Entity under an Energy Emergency Alert
Level 2 or Level 3, for the following reasons: (1) An EEA in effect for any BA or RSG other than the RE
experiencing the contingency should not give the RE an exemption from R1. The language makes the
assumption that both the EEA and contingency are affecting a single, specific RE – this is probably
what the SDT intended but the language used in R1 and R2 is too generic. (2) The “Applicability”
section clearly states that the standard does not apply to an RE under an EEA. Would it be sufficient
for the RE to restore ACE to within the dynamic BAAL limits instead of the “hard” criteria of zero or
pre-contingent ACE value within the 15 minute recovery period? Once an RE has gotten ACE within
the BAAL limit it is no longer burdening the interconnection – wouldn’t this be a sufficient recovery?
There should be coordination of the recovery required under BAL-002 with performance under the
BAL-001(BAAL) standard. PJM appreciates the SDT’s goal of drafting a continent-wide standard but
disagrees with the SDT’s approach of ‘one size fits all’ in defining a Reportable Balancing Contingency
Event. As previously stated, PJM believes that the Commission directive of defining a significant
(frequency) event is not satisfied by this standard. Additionally, using 500MW as an example, a loss
of 500MW may cause a significant frequency deviation at midnight on April 1st but not at 17:00 on
August 1st. The same 500MW loss may cause a significant frequency deviation in the Western
Interconnection but not in the Eastern Interconnection. PJM believes that this SDT and other SDT’s
have acknowledged that a ‘one size fits all’ approach is not always appropriate for all
Interconnections. In the proposed BAL-001-2, the BARC SDT proposes a definition of ACE that is only
applicable for the Western Interconnection. In BAL-003-1, that was recently approved by the industry
and the NERC BOT, the FR SDT identified different frequency excursion criteria for each
Interconnection that are used to identify candidate events for evaluating frequency response
performance. The FRI Report, approved by the NERC PC and accepted by the NERC OC, identified
different statistically derived delta frequencies for each Interconnection in developing IFRO’s. The
State of Reliability Report prepared annually by the NERC identifies “the triggers for significant
frequency events” that are specific to each Interconnection (ALR1-12 Assessment). As previously
stated, PJM respectfully suggests that the SDT give due consideration to redefining a Reportable
Balancing Contingency Event that satisfies the Commission directive of defining a significant
(frequency) deviation. Such a definition could resemble 80% of MSSC or a supply, load, or scheduling
event that results in a frequency deviation of XXmHz (depending on the Interconnection) in any
rolling XX second period. Previous work completed by the FR SDT and NERC staff could be leveraged
to this end. PJM believes this is one approach that could satisfy the directive set forth in Order 693.
Individual
Andrew Gallo
City of Austin dba Austin Energy
Agree
ERCOT

Individual
Angela P Gaines
Portland General Electric Company
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Portland General Eletric is supportive of this standard.
Individual
Kathleen Goodman
ISO New England Inc.
Yes
No
The last sentence in the definition is not needed, and should be removed. “The capacity may be
provided by resources such as Demand Side Management (DSM), Interruptible Load and unloaded
generation.” is the “How” to meet the contingency reserve requirement, which does not belong in a
definition. Suggest to remove this sentence. Because of the nature of using hourly integrated values,
Requirement R2 may not provide Operators on shift with sufficient information in a timely manner.
We recommend an alternative that uses a timer that begins to count up when the BA becomes
deficient in contingency reserve, resulting in a compliance violation should the condition persist for
105 minutes. Also, as proposed, it may be create burdensome reporting requirements so that an
hourly shortfall can be dismissed due to Balancing Contingency Events, for example.
No
There is no need to define the term Reserve Sharing Group Reporting ACE. This term is not
referenced or used in the Standard at all. If the RSG is obligated to meet the DCS requirement and
needs to return its ACE to zero or the Pre-Reportable Contingency Event value, then the Standard is
not explicit nor complete enough to place this obligation on the RSG.
Yes
Yes
Yes

Yes

Yes
There isn’t an appropriate technical justification for requiring a 500 MW threshold. If the justification
is simply to obtain more data samples, a 1600 data request is more appropriate than an enforceable
Standard. Suggest reverting back to the 80% threshold which has thus far, shown to provide for an
adequate level of reliability. The Standard can be simplified by replacing the existing requirements
with ones that read: • recover from a Reportable Event within 15 minutes; • replenish reserves within
90 minutes. As written, the Standard is overly complex.
Individual
Thad Ness
American Electric Power
Yes
No
It is not clear exactly what “other contingency requirements (such as Energy Emergency Alerts Level
2 or Level 3)” refers to.
Yes
No
Please see our response to Q2 in regards to the definition of Contingency Reserve. AEP disagrees with
the second half of R1 where it begins with “or… Its Pre-Reportable Contingency Event ACE Value, (if
its Pre-Reportable Contingency Event ACE Value was negative)…” . The language provided in this
section and its sub-bullets are extremely confusing. It appears that the intent is to set an expectation
for recovering from multiple contingency events, however the language provided is unnecessarily
complex and will likely confuse those responsible for meeting the requirements.
Yes
Yes
Yes
Yes
No
It is unclear whether or not the guidance document will eventually become a part of the officially
posted standard (in an appendix for example).
In addition to the comments provided to the earlier questions above, AEP offers the following
additional comments for consideration. AEP disagrees with the latest proposed definition of
“Pre-Reportable Contingency Event ACE Value”, which has been made ambiguous by the most recent
modifications. What is the intent of the drafting team in modifying the definition in this way? If this
definition were to be used, new tools would likely need to be developed in order to calculate the value
in this manner, as the operators would now be required to continuously calculate the ACE value based
on this new definition. The definition for, and application of, Contingency Event Recovery Period is
unnecessarily complex, confusing, and likely unpractical in its application. For example, if a unit was
taken out of service due to a controlled shut-down, the Real Time Operator’s most pressing
responsibility is balancing load and generation. Requiring this person to use the proposed
methodology to determine exactly the contingency event recovery period began would distract the
Real Time Operator from their core balancing responsibilities. Rather than take this approach, we

recommend retaining the existing way of determining when the recovery period begins, which is a
more straightforward and reasonable approach. In addition, the definitions for Contingency Event
Recovery Period and Contingency Reserve Restoration Period are quite similar and would most likely
prove confusing to industry in their application. Taking a conditional-based approach across multiple
standards does not serve the reliability of the bulk electric system, as it takes a straightforward
concept, overly complicates it, and distracts Real Time Operators from the core reliability objectives.
Group
Duke Energy
Greg Rowland
Duke Energy
No
• The definition is too broad. Using the phrase “or any series of such otherwise single events” leaves
much open to interpretation. In many cases it will not be clear when the 15-minute clock has been
triggered. • Regarding Subsection “C.”, it is also not clear what is meant by the “sudden loss of a
known load used as a resource”. Is the team referring to an interruptible load resource, fully loaded
and counted on for provision of contingency reserve? If so, would the sudden loss of the resource
mean that the load is inadvertently interrupted causing high ACE? We’re not aware of a proven
reliability risk that warrants a 15-minute recovery period from a high ACE. Or, is the team referring to
an interruptible load resource already implemented (curtailed) for a first contingency, and then
somehow losing the curtailment capability where the resource fully loads again causing low ACE
(second contingency)? If so, has any such event ever been documented to warrant placing a
statement subject to interpretation in the Standard? • Duke Energy suggests striking Subsection “C.”,
as loss of any load is covered under the BAAL in BAL-001-2. • Based upon the above, Duke Energy
suggests revising the definition to – “Balancing Contingency Event: Any single event described in
Subsection (A) or (B) below, or any combination of those events occurring within less than one
minute.” Duke Energy suggests revising Subsection “A.b” to read “And, that causes an unexpected
negative change to the responsible entity’s ACE”, and suggests revising Subsection “B” to state
“Sudden loss of an import, due to forced outage of transmission equipment that causes an
unexpected negative change to the responsible entity’s ACE.” Both changes are suggested to clarify
that this standard is applicable to the loss of resource causing an unexpected drop in ACE. To the
extent that Subsection “C” is retained, Duke Energy suggests a similar revision to insert the word
“negative”.
No
We would be in agreement except that it includes the term “Balancing Contingency Event”, and we
would need our above suggested changes made to that definition to be in agreement here.
No
Only BA’s participating in response to an event should be included in the Reserve Sharing Group
Reporting ACE calculation. As we commented on BAL-001-2, ACE should be fully defined in a manner
where Reporting ACE can be defined simply as the “The scan rate values of a Balancing Authority’s
ACE”.
Yes
We agree with the change to R1 to recognize emergency operations as long as the BAAL is
implemented in BAL-001-2, as it is the only viable standard for measuring real-time performance and
the BA’s impact on Interconnection frequency during such operation. Duke Energy agrees that the
proposed language in this standard will allow the BA to utilize its contingency reserves to continue to
serve load under an Energy Emergency Alert Level 2 or Level 3 while remaining compliant to BAL002; however under what circumstances, if any, should the Balancing Authority shed firm load as a
last resort to ensure that it remains compliant to Requirement R1 under normal operations? In our
opinion, the inability of a Balancing Authority to meet the 15-minute DCS compliance threshold does
not in itself represent a reliability issue. There are cases in the off-peak times especially where the
recovery is detrimental to Interconnection frequency. Some of the revisions in BAL-002-2 blur the
clear and well-established criteria of what triggers the DCS event. Too much is left up to after-the fact
compliance scrutiny, and operators need unquestionable guidance on this matter. Also, in the
definition of Contingency Reserve, add the word “NERC” before the word “contingency” for clarity.

No
Requirement R1 and R2 could provide a consistent continent-wide Contingency Reserve policy if the
definition of Balancing Contingency Event provided a “bright line” to the industry on what events
would be applicable to the determination of MSSC; we believe that Subsection “C.” of that definition
should be deleted, per our comment under question #1 above, and if the R2 allowed for other use of
Contingency Reserves. Requirement 2 refers to “Disturbance Recovery Period” and “Contingency
Reserve Recovery Period” which are no longer defined. Duke Energy would suggest the following
change: “Except during the Contingency Event Recovery Period and Contingency Reserve Restoration
Period, or during an Energy Emergency Alert Level 2 or Level 3, each Responsible Entity shall
maintain an hourly average amount of Contingency Reserve at least equal to its Most Severe Single
Contingency.” Language in Requirement R2 should also recognize that Contingency Reserves may be
used from time to time to aid in balancing aside from the loss of resource – today such use takes
places and does not impact compliance under DCS. Measure M2 requires that the Contingency
Reserve averaged over each clock hour is greater than or equal to the amounts identified in
Requirement 2 – however, as the amounts identified in Requirement R2 are allowed to be less than
MSSC, it is not clear why the language at the end places an exception only on the 105-minute
combined recovery and restoration period, and not on any period such resources may be utilized
under an EEA2 or EEA3. Duke Energy would suggest modifying Measure M2 to read at the end
“except during an Energy Emergency Alert Level 2 or Level 3, or within the first 105 minutes following
an event requiring the activation of Contingency Reserve.” Though an hourly average is proposed, it
is not practical for a BA to track its Contingency Reserves in a manner where it would make the
choice to increase its Contingency Reserves above the MSSC if it happened to drop below its MSSC for
some time in the same hour – it is an unnecessary activity to bring into real-time operations. Also, we
believe the Standard Drafting Team should carefully check to make certain that these new definitions
don’t impact other existing definitions. Though suggestions have been provided, Duke Energy does
not support the adoption of Requirement R2 and agrees with the comments provided by MISO.
Performance under the existing BAL-002 has been stellar without the need for an additional
requirement to track Contingency Reserves to the extent prescribed. The current DCS is a very
effective results-based standard. The existence of a requirement such as R2 will result in inefficient
utilization of resources, increased costs, inaccurate representation of resource capability, and other
negative consequences with no benefit to reliability.
No
We can’t agree, due to the current lack of clarity in the requirements.
Yes
No
We can’t agree, due to the current lack of clarity in the requirements.
• As the BAAL proposed in BAL-001-2 will address the loss of any resource, or any other change in
ACE causing a Balancing Authority to exceed its BAAL, it could be argued that there is no reliability
need to retain DCS. In 2007, the NERC Operating Committee supported the adoption of the BAAL and
a subsequent field trial of operating without DCS to determine if the Standard was still needed. Until
more experience is gained under the BAAL, Duke Energy supports having a Standard driving a
Balancing Authority to address the largest of its events as it does today, however we see no reliability
need to expand BAL-002 beyond the simple concept of measuring the recovery to the largest of the
BA’s resource losses – 80% or greater of the MSSC, and limited to MSSC, where the applicable events
are clearly understood by the operator. Duke Energy disagrees with applying compliance and
associated compliance reporting on an event-by-event basis, rather than allowing the quarterly
reporting currently provided under BAL-002. The measures for compliance should recognize that no
technical basis has been provided to support the 15-minute recovery required under Requirement R1
– compliance to a line drawn in the sand can be measured on a quarterly basis similar to today, as
real-time reliability needs will be met by the BA being held to compliance under BAAL. • Duke Energy
disagrees with the definition of “Reportable Balancing Contingency Event”. Given that all resource
losses will be captured by the BAAL under BAL-001-2, that there is no basis for using 500 MW as a
baseline for reporting, and that there has not been a demonstrated reliability need to move away
from our current reporting criteria of 80% or greater of the MSSC, Duke Energy does not support the

inclusion of the 500 MW threshold in the definition.. We believe that BAAL 30-minute response covers
all events, and DCS action is a 15-minute response intended to address large events. We agree with
MISO’s comment that currently DCS is measured quarterly, and the proposed Requirement R1 creates
an unnecessary event-by-event compliance evaluation. Adding the 500 MW threshold and multicontingent event expectation is excessive, with no benefit to reliability. • Duke Energy believes that
Reserve Sharing Group should have the flexibility to calculate a group ACE rather than just taking the
algebraic sum of all the BA ACEs.
Individual
John Seelke
Public Service Enterprise Group
Agree
PJm Interconection
Group
DTE Electric
Kent Kujala
DTE Electric
Agree
MISO
Individual
Keith Morisette
Tacoma Power
No
Tacoma Power is unfamiliar with the phrase, “… known load used as a resource …” We believe the
industry cannot interpret these words consistently. Instead, we suggest using the phrase, “…
interruptible load claimed as available reserves …,” which is Tacoma Power’s interpretation.
Yes
Yes
Yes
Yes
Yes
Yes
No
Tacoma Power does not understand - all levels state that the Responsible Entity recovered from the
event, yet they recovered to less than 100% of the required recovery. How can it be “recovered”
without reaching 100% in every case? Instead, we suggest that the VSLs recognize that the
Responsible Entity “partially recovered” from the event.
Yes
Tacoma Power appreciates the opportunity to provide comments. We cannot support this draft of the
standard because we are unfamiliar with the phrase, “… known load used as a resource …” in the
definition of a Balancing Contingency Event. Therefore, this phrase must be defined or replaced so
that there is no confusion within the industry and compliance authorities. We suggest using the
phrase, “… interruptible load claimed as available reserves …,” which is Tacoma Power’s
interpretation. In addition, the VSLs are very confusing. All levels state that the Responsible Entity

recovered from the event, yet they recovered to less than 100% of the required recovery. How can it
be “recovered” without reaching 100%? Instead, we suggest that the VSLs recognize that the
Responsible Entity “partially recovered” from the event.
Individual
Don Jones
Texas Reliability Entity
Yes
Definition of “Balancing Contingency Event” is slightly different in Implementation Plan as compared
to Standard (A.a.iii. Facility vs Facilities, B. Import vs import…). Definition of “Reportable Balancing
Contingency Event ” is different in Implementation plan as compared to Standard (Implementation
Plan does not include phrase “The 80% threshold may be reduced upon written notification to the
Regional Entity.”) The Applicability section in the Implementation Plan is also different than the
Standard.
Yes
The Contingency Reserve definition should mention a Reserve Sharing Group in addition to a BA.
Yes
Yes
R2- Disturbance Recovery Period is not defined and should be changed to Contingency Event
Recovery Period.
Yes
A Responsible Entity may have an internal Contingency Reserve policy that is different than the
proposed language in R2. While we understand the R2 states the minimum Contingency Reserve
amount, should R2 be re-worded to state that each Responsible Entity shall maintain an amount of
Contingency Reserve as least equal to its Most Severe Single Contingency or an amount per its
Contingency Reserve policy, whichever is larger? Ex. The MSSC in ERCOT is 1375 MW, but the
required minimum responsive reserve is 2300 MW, which is the amount necessary to maintain
adequate primary frequency response to meet the intent of the BAL-003 standard.
Yes
Yes
No
1) R1 VSL- At what point is the ACE measured in order to determine the % of required recovery. We
assume it is the lowest ACE value measured during the one-minute period for the Balancing
Contingency Event, but this should be clarified. 2) R2 VSL – A deficiency less than 5 hours is not
covered by the VSL. If the intent is to allow a certain amount of deficiency without penalty, that
should be clearly stated in the requirement and not implied in the VSL. 3) R2 VSL – Five hours in a
calendar quarter of not having sufficient Contingency Reserves seems too long, especially since
Contingency Event Recovery Periods and EEAs are excluded. We would recommend a shorter time
frame, e.g. 0-3 hours for lower VSL, 3-5 for moderate VSL, 5-10 for high VSL, and >10 for severe
VSL. Also, the time frame for each VSL level needs to state if it is cumulative or on a per-event basis
(we assume it is cumulative but it should be explicitly stated).
No
The equations and methodology on CR Form 1 seem flawed. The recovery requirement in R1 is based
on ACE, but the calculations in CR Form 1 are based on the MW lost. We believe the equations in CR
Form 1 and the Background Document should be modified to incorporate the elements of the ACE
equation into the calculations (i.e. frequency deviation and frequency bias in particular). For example,
a recent unit trip of 1300 MW occurred. Based on the frequency deviation, the lowest ACE during the
one-minute event period was -1900 MW. The language of the requirement and the CR Form 1 should
reflect the recovery of the ACE (1900 MW) rather than the MW lost (1300 MW) in this case.
1) In ERCOT, we have an existing process in place to analyze unit trips greater than 500MW.

However, other interconnections may find it overly burdensome to analyze these unit trips based on
their current size and loads. 2) R1, as stated, is an event-by-event obligation. A failure to recover for
one event would constitute a violation, even though the Responsible Entity may have performed well
for the remainder of the period. Is this the intent of the SDT? Would the SDT consider another
measure, such as evaluation of multiple events on a quarterly basis? 3) Does the SDT intend to retire
the existing “Disturbance Control Standard” definition? Do you need to modify definition of “Reserve
Sharing Group” to not reflect usage of “Disturbance Control Performance”? 4) The Reserve Sharing
Group Reporting ACE definition is different here than the Regulation Reserve Sharing Group Reporting
ACE definition provided in BAL-001-2, which is correct? (i.e. Does not have “at the time of
measurement” as last part of sentence). 5) How do you calculate a Reserve Sharing Group PreReportable Contingency Event ACE Value? We assume it is the algebraic sum of the ACEs of the BAs
that make up the Reserve Sharing Group, but it may need to be explicitly stated.
Individual
Oliver Burke
Entergy Services, Inc. (Transmission)
Agree
SERC OC Standards Review Group
Individual
Brian Murphy
NextEra Energy

Have the option also calculate ACE using the following formula: ACE = (NIA í1,6í%)$í)6
– IME
Individual
Robert Blohm
Keen Resources Ltd.
Yes
No

The definition is left vague, to enable "double counting" of reserve types. It is a definition not of
reserve "allocated" to contingency/restoration, but of reserve that is "usable" for
contingency/restoration and which includes the two other defined types of reserve, Frequency
Responsive and Regulating. This distinction, between "usable" and "allocated" remains notoriously
unclear in this definition, and in apparent contradiction to the provision against double-counting of
reserve in the "Guidance Document" currently in preparation. To make the distinction clear, and that
occasional "double counting" of reserve types is specifically being allowed by the BAL performance
standards, this definition needs to be broken into two definitions. The term "Contingency Reserve"
defined in the current definition should be changed to "Reserve Usable for Contingencies" which
should be the term used in requirement R2. A second, clear definition of "Contingency Reserve"
should be made for use in the Guidance Document, as reserve "allocated" for contingency/restoration,
and the term "Contingency Reserve" should thereby be made clearly usable in that document's
admonition against double counting of the three types of reserve: Frequency Responsive, Regulating,
and Contingency.
Yes
No
You mean not "possible issues" but "possible issues related to EOP standards". Otherwise, see answer
to question 2 about other issues.
No
As explained in my Comment to Question 2, the commonly used term "Contingency Reserve" needs
to be unpacked into two terms: "Contingency Reserve" (to be used in the "Guidance Document"
currently being prepared) and "Reserve Usable for Contingencies" (to be used in this standard instead
of "Contingency Reserve"). The FERC Directive 693 did not identify and sort out this ambiguity and
called simply for a requirement of undifferentiated "response" to a contingency, without distinguishing
between the three intrinsic "types" of response, namely Frequency Response, Regulating Response,
and Contingency Response, except to designate the "objective"/cause of the Response. All three types
of response can meet that objective. The FERC Directive then sought to expand the definition of
Contingency Reserve to include demand-side resources, and to set the requirement of a quantity of
"Contingency Reserve", without specifying "Contingency Reserve" as any particular reserve type. So,
yes, R2 does address the FERC Directive, but the FERC Directive is itself inadequate for failing to
make the all-important distinction between type of reserve, and usability of different reserve types to
meet a single reliability objective which would be some generalized "Responding" to a "Contingency"
without specifying the "type" of response which distinguishes reserve types. Rather than simply
"address" a technically uninformed FERC Directive, NERC should in its superior reliability
wisdom/competence seek to improve upon the FERC Directive and establish the precedent that FERC
takes technical direction from NERC, not the other way around and without opposing or contradicting
FERC.
Yes
Yes
Yes
No
The definition of "Best ACE" is unclear as: the "most positive ACE during the Contingency Event
Recovery Period occurring after the last subsequent event, if any (MW)". The meaning of "if any" is
specified only in the attached spreadsheet that makes "claiming" such a subsequent event "optional"
to the BA. In other words, a BA will not claim a subsequent event that makes the BA's compliance
worse. The purpose of this definition of "Best ACE" is to prevent R1's sanctioning a BA's avoiding noncompliance due to insufficient reserve, by incurring a subsequent contingency within the recovery
period to reduce the BA's recovery requirement. By this definition of "Best ACE" a BA will not claim a
subsequent event that makes the BA's compliance worse. A clearer alternative definition of "Best
ACE", that does not require the "optionality" obscurely lodged in the spreadsheet and that would
harmonize with the needed change to the R1 wording that I show in my Comment to Question 10,

would be "the least negative value if there are no positive values, or the most positive value of any
positive values, among the values of ACE occurring during the recovery period, unless it is the ACE to
which the addition of any subsequent events that occurred prior to or concurrently with it results in a
value that is the least negative value if there are no positive values, or the most positive value of any
positive values, among all such resultant values and the other ACE values during the recovery
period.”
The wording of the recovery target ACE in Requirement 1 needs to be replaced as follows: "less the
sum of the magnitudes of all subsequent Balancing Contingency Events that occur WITHIN THE
CONTINGENCY EVENT RECOVERY PERIOD [caps mine]" should be replaced by "less the sum of the
magnitudes of all subsequent Balancing Contingency Events that occur AT THE MOMENT OF
RECOVERY (OR NEAREST-RECOVERY), or beforehand [caps mine]". Otherwise, by containing the
word "all" in the selected wording, R1 sanctions a BA's avoiding non-compliance due to insufficient
reserve, by incurring a subsequent contingency within the recovery period to reduce the BA's
recovery requirement. Furthermore, the current R1 definition contradicts the definition of "Best ACE"
contained in the Background Document that was intended to preempt such BA behavior by defining
"Best ACE" as: the "most positive ACE during the Contingency Event Recovery Period occurring after
the last subsequent event, if any (MW)". The meaning of "if any" is specified only in the attached
spreadsheet that makes "claiming" such a subsequent event "optional" to the BA. In other words, a
BA will not claim a subsequent event that makes the BA's compliance worse. A clearer alternative
definition of "Best ACE", that does not require the "optionality" obscurely lodged in the spreadsheet
and that would harmonize with the needed change to the R1 wording, would be "the least negative
value if there are no positive values, or the most positive value of any positive values, among the
values of ACE occurring during the recovery period, unless it is the ACE to which the addition of any
subsequent events that occurred prior to or concurrently with it results in a value that is the least
negative value if there are no positive values, or the most positive value of any positive values,
among all such resultant values and the other ACE values during the recovery period.”
Group
Iberdrola USA
John Allen
Rochester Gas & Electric
Agree
NPCC
Individual
Steven Wallace
Seminole Electric Cooperative, Inc.
Yes
Yes
No
As written, it arbitrarily precludes the calculation of an RSG ACE for an entire RSG based upon the
aggregate frequency bias, and the RSG participants' net interchange with non-participants. The
Florida Reserve Sharing Group monitors participants' individual ACE, but calculates an RSG ACE based
on the aggregate frequency biases and net interchange with non-participants.
Yes
No
This standard ahs been and should continue to be results based. R2 imposes a tracking and
evidentiary requirement which is unreasonable and is not warranted by past performance and results.
If the logical next step to be standards proscribing the measurement, qualification, etc. for
contingency reserves?
No

Agree with the the VRF for R1, but not R2 for the reasoons described in response to Question 6.
No
Same response as Question 6.
No
Yes
Provide flexibility for an RSG ACE to be calculated based on aggregate participants frequency bias and
RSG interchange with non-participants.
Group
PPL NERC Registered Affiliates
Brent Ingebrigtson
LG&E and KU Services
No
The PPL NERC Registered Affiliates suggest striking the language “due to forced outage of
transmission equipment.” A responsible entity can cut a tag for reasons other than a forced outage of
transmission equipment (equipment OLs, contingency/stability/voltage criteria, etc.) – the sink BA
experiencing the loss of the import may not know the reason and thus not know if the loss meets the
definition of a Balancing Contingency Event. The SDT replied to this comment during the Formal
Comment Period, but missed the point. The curtailment would be communicated, however, the
reason, “due to …” would not necessarily.
No
The PPL NERC Registered Affiliates believe the proposed modifications actually introduce ambiguity
and error. Attempting to provide examples (such as…) in definitions is ill-advised as this adds
ambiguity to the definition as the list may be considered all inclusive by some and not by others. The
final sentence should be struck. As defined by NERC, Demand Side Management includes “all
activities” used to “influence” energy usage, which includes programs such as time of day rates, light
bulb replacement, and other efficiency programs which do not provide controllable capacity. It
appears the SDT may have intended to include the NERC defined term Direct Control Load
Management as an example, however, examples need not be included in definitions.
No
The PPL NERC Registered Affiliates believe the definition should include only those BAs participating in
the specific event, not simply all BAs that are members of the RSG. Suggest revising the definition as
follows: -- Reserve Sharing Group Reporting ACE: At any given time of measurement for the
applicable Reserve Sharing Group, the algebraic sum of the ACEs (as calculated at such time of
measurement) of all of the Balancing Authorities that are participating in the Balancing Contingency
Event. -No
The PPL NERC Registered Affiliates do not agree with the proposed modifications to the NERC defined
term Contingency Reserve as explained in our comment 2.
No
PPL NERC Registered Affiliates do not agree that the development of additional requirements is
necessary to meet the FERC directive for a continent wide policy. Additional comments on this topic
provided under question 10.

No

It is not clear to the PPL NERC Registered Affiliates why the SDT chose to use the loss of load
(negative loss values included in the CERTS statistics) when determining the reportable threshold for
BAL-002. The document fails to include the criteria that were used to define a “significant impact on
frequency”.
The PPL NERC Registered Affiliates offer the following comments: With respect to the proposed
definitions, it is not clear why the SDT modified each of the proposed definitions but is only requesting
input on a subset of the defined terms during this comment period. With respect to requirement 1, it
is suggested that the phrase “Except when an Energy Emergency Alert Level 2 or Level 3 is in effect,”
be deleted for the following reasons: 1) An EEA in effect for any BA or RSG other than the responsible
entity experiencing the contingency should not give the responsible entity an exemption from R1. For
example, an EEA in effect for a BA in Florida should not be a consideration for the performance of a
contingent responsible entity anywhere in the eastern interconnection. The language makes the
assumption that both the EEA and contingency are affecting a single, specific responsible entity – if
this is what the SDT intended, the language as currently written is too generic. 2) The Applicability
section clearly states that the standard does not apply to a responsible entity under an EEA. If the
SDT intends to include the exemption in the requirement language, it is suggest R1 is revised as
follows: “Except when an Energy Emergency Alert Level 2 or Level 3 has been requested by the
Responsible Entity, the Responsible Entity experiencing a Reportable …” . Also, we suggest it would be
more appropriate for the Responsible Entity to restore ACE to within the BAAL limits rather than the
“hard” zero or pre-contingent ACE value within the 15 minute recovery period. Once a responsible
entity has restored ACE within the BAAL limits it is no longer burdening the interconnection – this
would be a sufficient recovery. We suggest that a successful response by the responsible entity would
return ACE to the lesser of 0 or its real time BAAL limit (if its Pre-Reportable Contingency Event ACE
was positive or equal to zero) and similarly – ACE returned to the lesser of its Pre-Reportable
Contingency ACE Value or BAAL limit (if its Pre-Reportable Contingency Event ACE was negative).
With respect to R2, it is not clear if responsible entity experiencing a non-reportable Balancing
Contingency Event (i.e. a loss less than 500MW) is expected to maintain Contingency Reserves at
least equal to its MSSC. As currently written, it appears that R2 could require a Responsible Entity to
always carry Contingency Reserves equal or greater than its MSSC plus 500MW (or its reportable
threshold) so that Contingency Reserves will always exceed MSSC. With respect to measurement M2,
it is not clear if Contingency Reserves may fall below MSSC for the first 105 minutes (Contingency
Event Recovery Period plus Contingency Reserve Restoration Period) following any deployment of
Contingency Reserves. If so, this may resolve the current expectation as written in R2. However,
measures are not requirements and therefore, compliance is not judged through any potential
flexibility provided in M2 or the VSLs. Requirement 2 (along with the currently effective version 1 of
BAL-002) uses a capitalized term “Disturbance Recovery Period” that is not in the NERC Glossary of
Terms. The SDT may have intended to use the term Contingency Event Recovery Period in lieu of
Disturbance Recovery Period in requirement 2.
Group
Florida Municipal Power Agency
Frank Gaffney
Florida Municipal Power Agency

BAL-002, R1 states that the Responsible Entity shall demonstrate that it returned its ACE to zero (less
some modifiers); in other words, the standard requires ACE to be returned to an absolute number,
without a tolerance. I believe this is not the intent of the SDT, that they probably meant zero or

positive, or something like that; but, reading the requirement literally, I believe it would be difficult to
prove compliance using integrated values for ACE that will likely not equal zero.
Group
MISO Standards Collaborators
Marie Knox
MISO
No
No
The presently approved NERC definition for contingency seems adequate for this standard.
No
This change was not proposed in the drafting team’s SAR and we see no FERC directive to make this
change. RSGs have measurement processes that have worked well for quite some time. If the
drafting team has guidance on the measurement process, that should be put in a supporting
document rather than hard-coding additional obligations in the standard.
No
It needs a simple statement in the applicability section that the standard does not apply to BAs when
they are in EEA 2 or 3.
No
R2 has nothing to do with a Continent Wide Contingency Reserve Policy and there is nothing in the
drafting team’s SAR that calls for the implementation of a commodity standard. This requirement will
have significant negative unintended consequences. Reserves are an inventory intended to be used
when there is a reliability need. The first unintended consequence is that BAs are encouraged by this
requirement never to deploy their contingency reserves except for a DCS-reportable events. The
original Policy 1 noted many reasons for operating reserves. BAs whose ACE is extremely negative for
other reasons would be reluctant to deploy their contingency reserves because the timer would start
ticking on the “available hours” clock. The second unintended consequence for those BAs that don’t
withhold contingency reserves for non-DCS events is that they will be obliged to increase the amount
of contingencies the carry so they always have more reserves than their MSSC. This will increase
costs to our customers without a demonstrated need. DCS performance in North America has been
stellar compared to what was considered adequate performance under Policy 1. The last most
significant unintended consequence relates to the embedded expectation to recover from and
measure multi-contingent events beyond MSSC. When these events happen, something bigger is
going on. Transmission security is probably an issue. Forcing a knee-jerk expectation to drive ACE
back toward zero during a major event will likely do more harm than good. This is another thing that
wasn’t in the drafting team’s SAR nor in a directive. Events greater than MSSC should be reported,
but not evaluated for compliance. While it’s fine to embed some of the calculations in the background
document in a reporting form, events greater than MSSC should be excluded from compliance
evaluation. A fundamental flaw in R2 is that drafting team has implemented a commodity expectation
that the BA must have contingency reserves above MSSC at all times and yet has provided no clear
definition on how this is measured (does it include all generation headroom available in 10 minutes?
In 15 minutes? What about resources that are also providing AGC? Does their instantaneous
headroom count? Are load resources available in 15 minutes or 10 minutes counted? What type of
proof of deliverability is required? Some of the background information implies that frequency
responsive resources must be removed from the Contingency Reserve calculation. How much? All
headroom? Enough to provide the IFRO? This proposal sets a commodity standard which is not in
keeping with the superior approach of having performance-based standards. Not all BAs have the
same needs for the various types of operating reserves. Performance is the ultimate demonstration of
adequacy. We believe the way a way to achieve the Commissions directive for a continent wide
“contingency reserve” policy is for the drafting team, in concert with the NERC operating committee,
to create a policy document that outlines the factors that the BA uses in performing an assessment of
needed frequency responsive, regulating and contingency reserves. The document the drafting team
is working on is a good start. The policy should provide simple definitions for frequency responsive,
regulating, contingency, and replacement reserves. Once the policy has undergone comment through

the standards process (this was the directive in 693), NERC should add these four types of reserves
to “Attachment 1-TOP-005 Electric System Reliability Data” with the expectation in the policy that
Reliability Coordinators collect this information in real time for use in the EEA process.
No
We believe the requirement itself is inappropriate, so any VRF is unnecessary.
Yes
No
Requirement 1 should not be an event by event obligation. A quarterly measure has worked quite
well. We disagree with the current R2 so we cannot offer a suggestion to improve its VSL.
No
There first needs to be agreement on the requirements before there is concurrence with the
background document.
Besides the concerns presented above, we are troubled with the significant changes that will occur
within R1 compared to today’s DCS and the fact that the drafting team is asking no questions about
those changes. The current DCS is measured on a quarterly basis. The way the proposed requirement
1 and VSL are crafted, this is now an event by event compliance evaluation. When you add the fact
that the team is also embedding a 500 MW reporting threshold and the multi-contingent event
expectation, this exposes the industry to a heavy-handed standard for no reliability need. It should be
noted that DCS performance has been stellar across North America compared to what existed under
Policy 1. The changes being implemented are well beyond what was in the drafting team’s SAR and
the Order No. 693 directives. The SAR for the drafting team was basically to clean up the V0 clutter in
the standard and address Order No 693 directives. The only two true requirements in the V0 standard
are to recover from reportable events in 15 minutes and replenish reserves within 90 minutes. These
should be the basis of BAL-002-1. A Contingency Reserve Policy Guideline document in conjunction
with the recommendations below should be sufficient to meet the drafting team SARs and the
directives: • Preserve the two true requirements today (recover from reportable events within 15
minutes and replenish reserves in 90 minutes). • Provide clarity in the compliance section of the
standard or the background document how events > MSSC are reported. Note: We believe it is
acceptable to put something in the compliance section of the standard that notes if the same event >
than MSSC occurs within 3 years, the BA should be held to the DCS for that contingency. • Due to
concerns we have in BAL-013, we believe the reporting form for BAL-002 should also have a reporting
slot for large loss of load events (Order No. 693 directive), but for reasons we state in BAL-013,
believe that these should be excluded from compliance evaluation. Also BAL-001’s RBC is a more
effective way to meet the FERC directive for loss of load events. • The continent-wide contingency
reserve policy should be a separate guidance document under the purview of the NERC Operating
Committee with comments collected under the standards process along with this standard. This meets
the 693 directive. The policy document should provide guidance on how the BA should assess the
necessary amount of reserves as well as provide simple definitions of the different types of reserves.
Once these terms are defined and commented on by the Industry in the policy, NERC should add
these four types of reserves to “Attachment 1-TOP-005 Electric System Reliability Data” with the
expectation in the policy that Reliability Coordinators collect this information in real time for use in the
EEA process. The policy could ask the BAs to initially review and assess their needs and relay this to
their RC. The policy would be available for re-review if the BA’s performance approaches noncompliance. • The standard should be based on the lesser of 80% of MSSC, 1000MW, or a lower value
chosen by the Balancing Authority.
Group
Tampa Electric Company
Ronald L Donahey
Tampa Electric Company
Agree
Duke Energy
Individual
Christopher Wood

Platte River Power Authority
Agree
Public Service Company of Colorado (Xcel Energy)
Group
Southern Company: Southern Company Services, Inc.; Alabama Power Company; Georgia Power
Company; Gulf Power Company; Mississippi Power Company; Southern Company Generation;
Southern Company Generation and Energy Marketing
Pamela R. Hunter
Southern Company Operations Compliance
Yes
Yes
No
The definition should include only the BAs asked to participate in the reserve recovery event.
Yes
No
The proposed requirement would have significant negative consequences as Reserves are an
inventory intended to be used when there is a reliability need. A BA could be encouraged to never
deploy their CRs except for during a DCS-reportable event. The original Policy 1 noted many reasons
for operating reserves. BAs whose ACE is extremely negative for other reasons would be reluctant to
deploy their contingency reserves because the time would start ticking on the ‘available hours’ clock.
Additionally, BAs that don’t withhold CRs for non-DCS events might feel the need to increase the
amount of contingencies they carry in order to always have more reserves than their MSSC which in
turn, would increase customer costs without a demonstrated need. We suggest that not all BAs have
the same needs for the various types of operating reserves and that performance is the
demonstration of adequacy. We suggest the SDT work with the NERC OC to create a policy document
that outlines the factors the BA uses in performing an assessment of needed frequency responsive,
regulating and contingency reserves and provide simple definitions for frequency responsive,
regulating, contingency, and replacement reserves. Once the policy has undergone comment through
the standard’s process, we suggest that NERC add these four types of reserves to ‘Attachment 1-TOP005 Electric System Reliability data” with the noted expectation that RCs collect this information in
real time for use in the EEA process. While we agree with the principle of a BA maintaining
Contingency Reserves to respond to its MSSC, the proposed R2 puts the BA at risk if CR reserves fall
below its MSSC for any single sampling period. For example, BAs with a 2 second sampling interval
would be at greater risk than a BA with a 6 second sampling interval. While the SDT has attempted to
resolve this issue in the proposed Measures and VSLs, we suggest that specific language be included
in R2 and not just in the Measure (SERC OC). A reference to the integrated clock hour should be
included in R2 as in the Measure.
Yes
It is difficult to agree with the VRFs while disagreeing with the standard as proposed.
Yes
Yes
Requirement 1 should not be an event by event obligation. A quarterly measure has worked quite
well. We disagree with the current R2 so we cannot offer a suggestion to improve its VSL.
No
The Background Document states on page 4 that “FERC Order 693 (at P355) directed entities to
include a Requirement that measures response for any event or contingency that causes a frequency
deviation.” We disagree with this interpretation of the Commission’s directive. In Order 693 (P355)
the Commission declined to define a ‘significant deviation as a frequency deviation of 20 mHz’, but

instead directed the ERO ‘to define a significant deviation and a reportable event’. The Commission
directed that ‘loss of supply, loss of load and significant scheduling problems, which can cause
frequency disturbances,’ must be taken into account when developing the aforementioned definitions.
We believe that the Commission clearly did not intend that any event that causes a frequency
deviation, no matter how small, be included in DCS reporting, but rather that a significant frequency
deviation be defined by the ERO. The definition of a Reportable Balancing Contingency Event should,
but currently does not, reflect such a definition. The Background Document on page 6 points to
statistical frequency data supplied by CERTS in Attachment 1 to support the 500 MW reporting
threshold. While Attachment 1 shows the box plots used for this determination, it does not provide a
narrative defining the sampling data or method. It appears that frequency deviations resulting from
loss of load and loss of supply were included in the same data sample. We question whether this is
appropriate and believes that in order for the industry to effectively evaluate the proposed criteria, a
narrative needs to be added to Attachment 1 that explains the data sample and method. We suggest
that additional details be provided in the background document relating to the methodology for
development of the reporting thresholds.
There is an embedded expectation to recover from and measure multi-contingent events beyond
MSSC. When these events happen, something bigger is going on. Transmission security is probably an
issue. Forcing a knee-jerk expectation to drive ACE back toward zero during a major event will likely
do more harm than good. This is another thing that wasn’t in the drafting team’s SAR or in a
directive. Events greater than MSSC should be reported but not evaluated for compliance. While it’s
fine to embed some of the calculations in the background document in a reporting form, events
greater than MSSC should be excluded from compliance evaluation. We appreciate the SDT’s goal of
drafting a continent-wide standard but disagree with the SDT’s approach of ‘one size fits all’ in
defining a Reportable Balancing Contingency Event. As previously stated, we believe that the
Commission directive of defining a significant (frequency) event is not satisfied by this standard.
Additionally, using 500 MW as an example, a loss of 500 MW may cause a significant frequency
deviation at midnight on April 1st but not at 17:00 on August 1st. The same 500 MW loss may cause
a significant frequency deviation in the Western Interconnection but not in the Eastern
Interconnection. We believe that this SDT and other SDT’s have acknowledged that a ‘one size fits all’
approach is not always appropriate for all Interconnections. In the proposed BAL-001-2, the BARC
SDT proposes a definition of ACE that is only applicable for the Western Interconnection. In BAL-0031, that was recently approved by the industry and the NERC BOT, the FR SDT identified different
frequency excursion criteria for each Interconnection that are used to identify candidate events for
evaluating frequency response performance. The FRI Report, approved by the NERC PC and accepted
by the NERC OC, identified different statistically derived delta frequencies for each Interconnection in
developing IFRO’s. The State of Reliability Report prepared by the NERC identifies “the triggers for
significant frequency events” that are specific to each Interconnection. We respectfully suggest that
the SDT give due consideration to redefining a Balancing Contingency Event and Reportable Balancing
Contingency Event that satisfies the Commission directive of defining a significant (frequency)
deviation. Such a definition could resemble 80% of MSSC or a supply, load, or scheduling event that
results in a frequency deviation of XXmHz (depending on the Interconnection) in any rolling XX
second period. Previous work completed by the FR SDT and NERC staff could be leveraged to this
end. We believe this is one approach that could satisfy the directive set forth in Order 693. In R1 and
R2, delete the language related to an RE under an Energy Emergency Alert Level 2 or Level 3, for 2
reasons: (1) An EEA in effect for any BA or RSG other than the RE experiencing the contingency
should not give the RE an exemption from R1. E.g. an EEA in effect for a BA in Florida should not be a
consideration for the performance of a contingent RE anywhere in the EI. The language makes the
assumption that both the EEA and contingency are affecting a single, specific RE – this is probably
what the SDT intended but the language used in R1 and R2 is too generic. (2) The “Applicability”
section clearly states that the standard does not apply to an RE under an EEA. Words could be added
to R1 and R2 to clarify that the contingent RE is also the RE experiencing an EEA but a better solution
is to simply delete the EEA related language from R1 and R2, Would it be sufficient for the RE to
restore ACE to within the dynamic BAAL limits instead of the “hard” criteria of zero or pre-contingent
ACE value within the 15 minute recovery period? Once an RE has gotten ACE within the BAAL limit it
is no longer burdening the interconnection – wouldn’t this be a sufficient recovery? There should be
coordination of the recovery required under BAL-002 with performance under the BAL-001(BAAL)
standard. We suggest that a successful response by the RE would return ACE to the lesser of 0 or its
real time BAAL low limit (if its Pre-Reportable Contingency Event ACE was positive or equal to zero)

and similarly – ACE returned to the lesser of its Pre-Reportable Contingency ACE Value or BAAL low
limit (if its Pre-Reportable Contingency Event ACE was negative). If the interconnection frequency is
high – why require a BA to increase generation more than is necessary to meet its BAAL low limit? If
interconnection frequency is low, the BAAL low limit as well as the zero or pre-contingent ACE rule
would still apply.
Individual
Spencer Tacke
Modesto Irrigation District

No
It is in conflict with the very definiton of a balancing authority.
Yes

No

A technical justification for the "16 second interval" for ACE and the "105 minutes" value for
Contingency Reserve demonstration needs to be added.
Individual
Thomas Washburn
FMPP
Agree
FMPA
Group
ERCOT
H. Steven Myers
ERCOT ISO
Yes
Yes
ERCOT ISO suggests that the SDT consider the following changes so that the definition of the
Contingency Reserve clearly accommodates resources eligible under the respective BA rules to
provide Contingency Reserve for that BA: "The provision of capacity that may be deployed by the
Balancing Authority to respond to a Balancing Contingency Event and other contingency requirements
(such as Energy Emergency Alerts Level 2 or Level 3). The capacity may be provided by 'resources
eligible under the respective BA rules, including, but not limited to,' resources such as Demand Side
Management (DSM), Interruptible Load and unloaded generation."
Yes
Yes
Yes

Yes
Yes
Yes
ERCOT ISO supports the intention of the standard BAL-002-2 R1 to restore ACE back to predisturbance ACE but not necessarily to zero or the pre-disturbance ACE. The ACE recovery goal should
be pre-disturbance levels. Therefore, ERCOT suggests the SDT establish a (epsilon1*Frequency
Bias*10) band around the pre-disturbance ACE or zero ACE, and, if during recovery ACE is recovered
within this range, entities would be compliant. This structure of establishing a goal, but providing for a
compliance "floor" based upon the proposed range, will achieve the desired reliability benefits while
also providing a reasonable degree of flexibility for circumstances where recovery to the exact predisturbance level is difficult to achieve, and unnecessary to ensure reliability. ERCOT ISO also
suggests that the 500 MW threshold be removed from the definition of Reportable Balancing
Contingency Event. This requirement would impose an undue burden. There is no reliability reason to
require mandatory reporting for these smaller events. It will merely create an administrative
obligation with no corresponding reliability benefits. For instance, currently ERCOT ISO would typically
need to report less than five events annually, but this new standard would increase this reporting
burden to over 50 each year (based upon 2012 disturbances), without any corresponding reliability
benefits. Accordingly, this obligation should be removed. If the SDT elects not to remove the 500 MW
threshold generally, ERCOT ISO suggests that the threshold be removed for single-BA
Interconnections. The threshold for single-BA Interconnections should be established as 80 percent of
the MSSC. ERCOT ISO is voting "yes", but has reservations as described above and requests that the
SDT revise the standard accordingly.
Individual
Si Truc PHAN
Hydro-Quebec TransEnergie
No
The definition is not explicitly clear about normal operating actions such as special protection system
(SPS) actions. Certain transmission events may lead to generation rejection so the system stays
stable after the fault. If we interpret the proposed definition and use the same terminology, these
actions are planned, the change on the ACE is not unexpected, and they could be considered as a
secondary event. The generation does not become unavailable following the trip. Consequently, these
events would not classify as Balancing Contingency Events. During the 04/02/2013 webinar, the
Standard Drafting Team provided an answer in this direction. We then understand that a CR Form 1
should not be filled for these types of events. However, we believe that the Balancing Contingency
Event definition should be clarified to minimize the risk of misinterpretation if this is the SDT’s intent.
We suggest adding a bullet in the definition stating that normal operating characteristics of a unit or a
system such as SPS actions do not constitute a sudden or unanticipated loss and are not subject to
this definition. Additionally, some single contingencies may lead to generation loss as well as load loss
after the breaker operations. For example, if 1200 MW of generation is loss and 1000 MW of DC
converters at the same time, the net loss for the grid is 200 MW, which would be under the
Reportable Balancing Contingency Event threshold. For this reason, the Balancing Contingency Event
definition should include the notion of net loss for the grid.
Yes
Yes
Yes
Yes

Yes
Yes
Yes
Yes

Group
ACES Standards Collaborators
Jason Marshall
ACES
No
(1) We appreciate the changes that have been made to the Balancing Contingency Event definition. It
is much less complicated and more clear as a result. However, there still has not been a justification
provided for the need of the definition. There is a statement in the background document that the
previous version of the standard was “broad and could be interpreted in various manners”. A specific
explanation how the definition addresses the ambiguity should be provided. (2) We disagree with
including subsection (c) in the Balancing Contingency Event definition. Subsection (c) includes sudden
“loss of a known load used as a resource”. Loss of a load will result in positive ACE regardless of
whether it is being used a resource or not. As a result, BAL-002-2 R1 will be duplicative with BAL013-1 R1. Both will compel recovery of ACE from the loss of a load. Think of it this way. If a 1000 MW
load is used as a resource to respond to a BA’s ACE that is at -100 MW, there would be 900 MW of
load remaining once the load is reduced. If that load is then lost, ACE goes to 900 MW. Shouldn’t this
be covered by the proposed BAL-013-1?
No
Please strike the last sentence of the definition. It is an explanation of what may constitute
contingency reserve and is not actually part of the definition. It should be included in the background
document. We understand the reason for the inclusion may be in response to a directive to further
the Commission’s policy on expanding the use of DSM. However, the use of DSM has expanded
significantly since the directives were issued and could be said to have been “overcome” by events. It
is well understood within this industry that DSM may be used as a resource. The drafting team could
include an explanation in the application guidelines or the background document that would explain
that DSM could be used among other resources.
No
We believe the definition as proposed is already a common understanding and is not needed. We
simply do not see how it adds value. Further, having multiple definitions for ACE creates confusion
and is simply not needed.
No
(1) We do believe that it is helpful to clarify that a BA does not have to comply with recovering ACE
and contingency reserves when it is in an EEA 2 or 3. It certainly would not make sense to go to the
extreme of shedding firm load to recover ACE or contingency reserves if a BA was simply out of
balance with no transmission security issues, system frequency issues or stability issues. There are
standards requirements such as operating within IROLs/SOLs that would deal with these other
reliability issues and provide the indication if load needed to be shed to address the deficient BA. A
more efficient way to address this issue may be to apply the restriction in the applicability section. (2)
It would be helpful if the drafting team explained what the conflicts with the EOP standards are.
Besides the one identified above, are there others? The background document states that there are
conflicts but does not explain them. It is difficult to judge if the issue was addressed without an
adequate explanation.
No

(1) We are concerned that this requirement will have unintended consequences. As written, a BA will
be forced to only deploy contingency reserve for responding to resource contingencies. Consequently,
the BA will have to carry more operating reserves which increases their operating costs tremendously
without commensurate reliability benefit. Furthermore, there is no data indicating that operating
reserves carried by BAs today are insufficient. (2) While contingency reserve is just one type of
operating reserve and is intended for use to respond to contingent events, a BA should not be
restricted to deploying it only for contingent events. There may be other reasons for a BA to have a
large negative ACE (i.e. units don’t ramp as expected) and the BA should be free to call upon its
contingency reserve to recover ACE in such a situation. Since the FERC directive that is driving this
requirement is to establish a continent wide policy on contingency reserve, a better solution would be
for NERC to write an operating policy describing appropriate uses of various types of contingency
reserves. A guideline document would provide better details for an operating policy than a
requirement.
No
We agree with the VRF for requirement R1 but do not agree with requirement R2 as written. Thus, we
do not agree with the VRF for Requirement R2.
Yes
No
We disagree with the VSLs for both requirements. The VSLs for requirement R1 raise the bar
significantly for compliance without a technical justification. Today, DCS compliance is determined by
a quarterly average of response to events. Thus, failure to recover ACE for two events within the
same quarter would be a singular violation. As proposed, the new VSLs would treat each event as a
separate violation. Without significant justification, we cannot agree with this change to the VSLs.
Because we do not agree with Requirement R2, we do not agree with the corresponding VSLs.
No
(1) The background document needs to explain the conflict between BAL-002 and EOP-002 in detail
rather than just stating that a conflict exists. (2) There is a statement on page 5 just before the
Rationale by Requirement section that there are other definitions that have been added or modified.
An explanation of what these are would be helpful. (3) The formulas starting on page 8 are overly
complicated in an attempt to address the few situations where there are additional generator
contingencies that occur shortly before or during the ACE recovery window. We suggest starting with
simple formulas that consider that predominant situation where only one generator contingency
occurs. Then build the more complicated formulas on that. It will be easier to explain. We also
suggest using pictures to explain the formulas. For example, a graph showing the loss of a unit before
and after the current contingency would help explain the formulas. The graph should include labels
such as what ACE_BEST, ACE_PRE, and MEAS_CR_RESP are.
(1) We cannot support a 500 MW threshold for a Reportable Balancing Contingency Event. The
number is arbitrary without any technical justification. The background document explains how the
drafting team reviewed CERTS data to arrive at the conclusion that a 100 MW threshold would cover
all frequency events. Correctly, the drafting team determined that this was simply an unrealistic
threshold and would not provide any additional reliability value. The background document then
explains that the drafting team decided “to capture the majority of events having significant impact
on frequency” by setting the threshold to 80% of the MSSC or 500 MW. It did not explain which value
would do this or why it was important “to capture the majority of events”. Furthermore, there is no
explanation why 500 MW is necessary when today 80% of MSSC is used. Has the use of 80% of
MSSC resulted in an unreliable system? Thus, we can only conclude the value is arbitrary. Please
remove the 500 MW value. (2) Additional justification is necessary to change the pre-disturbance
calculation from an average of 10 to 60 seconds of ACE data prior to the disturbance to a 16-second
interval. There is no explanation of this in the background document and we cannot support such a
change without a justification for how it supports reliability. Furthermore, it is not consistent with
BAL-005-0.2b which requires ACE calculation on at least a six second basis. A BA using a six-second
sample rate could be viewed as being out of compliance if they used either two (12 seconds) or three
(18 seconds) samples since they cannot use exactly 16 seconds of data. Furthermore, using only two
or three samples could lead to unrealistic averages particularly if there are any glitches in the data.
What does an entity do if a scan was skipped or there was a data spike? More samples would make it

less likely for this to be an issue. (3) The purpose needs to be modified. Please strike “balances
resources and demand and”. The purpose of the standard is to recover ACE following a Reportable
Balancing Contingency Event. The portion that needs to be struck is addressed by BAL-001. (4) The
drafting team has an opportunity to assist NERC in moving the Reliability Assurance Initiative along
and showing some of the first fruits of the initiative. One of the key white papers written for the
initiative focuses on the reducing the data requirements and retention periods necessary for the
compliance and enforcement process. NERC compliance has a stated goal of reducing the data
retention burden on registered entities. The data retention required for the current versions of this
standard exceed what is necessary and this draft version perpetuates the problem. All BAs currently
must submit monthly data to their regional entities for this standard which clearly shows whether
they are compliant or not. Then they are still required to retain three years worth of data. Since the
regional entities already have the data and know whether they are compliant or not, what reliability
value does three years of data provide? None. The new version will only perpetuate this issue. In
response to our previous comments, the drafting team indicated that the monthly reporting is not
required by the standard and is up to the region. While this is true, it is highly unlikely that the
regional entities will change this monthly reporting burden given that the standard is conceptually the
same as the existing standard. Furthermore, the drafting team and NERC staff can review the issue
with regional entity compliance personnel to confirm their plans for monthly reporting. If they do plan
to continue with the monthly reporting, then no more than six months of data is necessary and we
request that the standard should be changed. It will demonstrate a good faith effort on the part of
NERC to move the RAI forward. (5) The data retention section is inconsistent with the NERC Rules of
Procedure. Section 3.1.4.2 of Appendix 4C – Compliance Monitoring and Enforcement Program states
that the compliance audit will cover the period from the day after the last compliance audit to the end
date of the current compliance audit. Since a BA is on a three-year audit cycle, the period from the
previous audit will be about 3 years. It could be a little more or a little less. However, the data
retention section of “the current year, plus three previous calendar years” (which could be up to four
years) actually could exceed this three year audit cycle period. Consider if a BA completed their last
audit on November 15, 2010. Their audit cycle would require another audit in 2013. Let’s assume this
is scheduled for December 15, 2013. This means the audit period is 3 years and 1 month. It also
means per the Rules of Procedure that NERC cannot review any period prior to November 15, 2010
for compliance unless there is an outstanding investigation. Per the data retention section, on
December 15, 2013, the date of the audit, the BA would have to retain data for all of 2013 as well as
all of the data for 2010, 2011 and 2012. By the Rules of Procedure, the auditors could not review any
data prior to November 15, 2010. Thus, the registered entity would be compelled to retain for 11.5
months for which NERC is not allowed to review. How does this benefit reliability? The data retention
period should be changed to retain data since the last audit. Changing the data retention period to be
no longer than since the last audit would show a good faith effort in moving the RAI along. (6) The
VSLs for Requirement R2 need to be justified. There is no explanation provided for the values chosen
for the various thresholds. For example, the Lower VSL covers contingency deficiency for a period of 5
to 15 hours. Why shouldn’t this go to 20, 30, 40 or any other number of hours? Without a
justification, we can only assume the numbers were selected arbitrarily. We are also confused by the
Lower VSL since it starts at 5 hours. Does this mean that a BA can be deficient of contingency
reserves up to 5 hours without a violation occurring? (7) There is no explanation for why Reportable
Disturbance is not a satisfactory definition as used in the existing standard and why it is replaced with
Reportable Balancing Contingency Event. Furthermore, it is not proposed to be retired. If the term will
no longer be used, it should be retired. (8) Thank you for the opportunity to comment.
Individual
John Bee on Behalf or Exelon and its Affiliates
Exelon

While we appreciate the work done since previous versions of the project, and recognize the clarity
gained by eliminating reference to Balancing Contingency Events with a future impact to ACE, we feel
that additional confusion has been inserted by the sub-points of R1. Given that the recovery
requirement is a relatively short time-frame, the ability to quickly determine the recovery obligation is
critical to the ability to ensure compliance. We appreciate that the drafting team is attempting to
accommodate the notion that a prior Balancing Contingency Event might impact any future events,
but the methodology given for determining the recovery threshold is overly complex, and represents
a significant barrier to a system operator's ability to interpret the requirement in Real Time and
respond appropriately.
Individual
William O. Thompson
NIPSCO
Agree
MISO
Group
Tennessee Valley Authority
Dennis Chastain
Tennessee Valley Authority
Agree
SERC OC Standards Review Group
Individual
David Gordon
Massachusetts Municipal Wholesale Electric Company
Agree
Northeast Power Coordinating Council, Inc (NPCC) ISO New England, Inc.
Group
Oklahoma Gas & Electric
Terri Pyle
Oklahoma Gas & Electric
No
The definition of Reportable Balancing Contingency Event includes “the lesser of 80 percent of the
MSSC or 500 MW”. We believe that the threshold of 500 MW is too low. This is going to result in an
excessive number of “reportable” events that do not have an impact on reliability. The retrieval and
analysis of data will be burdensome and provide little value.
Yes
Yes
Yes
Yes
Yes
Yes

Yes
Yes
Remove the 500 MW threshold in the definition of Reportable Balancing Contingency Event
Group
IRC-SRC
Terry Bilke
MISO
No
We don't see the need for the added definition.
No
The presently approved NERC definition for contingency reserve seems adequate for this standard.
No
This change was not proposed in the drafting team’s SAR and we see no FERC directive to make this
change. RSGs have measurement processes that have worked well for quite some time. If the
drafting team has guidance on the measurement process, that should be put in a supporting
document rather than hard-coding additional obligations in the standard.
No
All that’s needed is a simple statement in the applicability section that the standard does not apply to
BAs when they are in EEA 2 or 3.
No
We believe this requirement will have significant negative unintended consequences. Reserves are an
inventory intended to be used when there is a reliability need. The first unintended consequence is
that BAs are encouraged by this requirement never to deploy their contingency reserves except for a
DCS-reportable events. The original Policy 1 noted many reasons for operating reserves. BAs whose
ACE is extremely negative for other reasons would be reluctant to deploy their contingency reserves
because the timer would start ticking on the “available hours” clock. The second unintended
consequence for those BAs that don’t withhold contingency reserves for non-DCS events is that they
will be obliged to increase the amount of contingencies the carry so they always have more reserves
than their MSSC. This will increase costs to our customers without a demonstrated need. DCS
performance in North America has been stellar compared to what was considered adequate
performance under Policy 1. The last significant unintended consequence relates to the embedded
expectation to recover from and measure multi-contingent events beyond MSSC. When these events
happen, something bigger is going on. Transmission security is probably an issue. Forcing a knee-jerk
expectation to drive ACE back toward zero during a major event will likely do more harm than good.
This is another thing that wasn’t in the drafting team’s SAR or in a directive. Events greater than
MSSC should be reported, but not evaluated for compliance. While it’s fine to embed some of the
calculations in the background document in a reporting form, events greater than MSSC should be
excluded from compliance evaluation. This proposal sets a commodity standard which is not in
keeping with the superior approach of having performance-based standards. Not all BAs have the
same needs for the various types of operating reserves. Performance is the demonstration of
adequacy. We believe the way a way to achieve the Commission’s directive for a continent wide policy
is for the drafting team, in concert with the NERC operating committee, to create a policy document
that outlines the factors that the BA uses in performing an assessment of needed frequency
responsive, regulating and contingency reserves. The policy should provide simple definitions for
frequency responsive, regulating, contingency, and replacement reserves. Once the policy has
undergone comment through the standards process (this was the directive in 693), NERC should add
these four types of reserves to “Attachment 1-TOP-005 Electric System Reliability Data” with the
expectation in the policy that Reliability Coordinators collect this information in real time for use in the
EEA process.
No
We believe the requirement itself is inappropriate, so any VRF is unnecessary.

Yes
No
Requirement 1 should not be an event by event obligation. A quarterly measure has worked quite
well. We disagree with the current R2 so we cannot offer a suggestion to improve its VSL.
No
There first needs to be agreement on the requirements before there is concurrence with the
background document.
Besides the concerns presented above, we are troubled with the significant changes that will occur
within R1 compared to today’s DCS and the fact that the drafting team is asking no questions about
those changes. The current DCS is measured on a quarterly basis. The way the proposed requirement
1 and VSL is crafted, this is now an event by event compliance evaluation. When you add the fact that
the team is also embedding a 500 MW reporting threshold and the multi-contingent event
expectation, this exposes the industry to a heavy-handed standard for no reliability need. It should be
noted that DCS performance has been stellar across North America compared to what existed under
Policy 1. The changes being implemented are well beyond what was in the drafting team’s SAR and
the Order No. 693 directives. The SAR for the drafting team was basically to clean up the V0 clutter in
the standard and address Order No 693 directives. The only two true requirements in the V0 standard
are to recover from reportable events in 15 minutes and replenish reserves within 90 minutes. These
should be the basis of BAL-002-1. Our recommendation are: • Preserve the two true requirements
today (recover from reportable events within 15 minutes and replenish reserves in 90 minutes). •
Provide clarity in the compliance section of the standard or the background document how events >
MSSC are reported. Note: We believe it is acceptable to put something in the compliance section of
the standard that notes if the same event > than MSSC occurs within 3 years, the BA should be held
to the DCS for that contingency. • Due to concerns we have in BAL-013, we believe the reporting
form for BAL-002 should also have a reporting slot for large loss of load events (Order No. 693
directive), but for reasons we state in BAL-013, believe that these should be excluded from
compliance evaluation. • The continent-wide contingency reserve policy should be a separate
guidance document under the purview of the NERC Operating Committee with comments collected
under the standards process along with this standard. This meets the 693 directive. The policy
document should provide guidance on how the BA should assess the necessary amount of reserves as
well as provide simple definitions of the different types of reserves. Once these terms are defined and
commented on by the Industry in the policy, NERC should add these four types of reserves to
“Attachment 1-TOP-005 Electric System Reliability Data” with the expectation in the policy that
Reliability Coordinators collect this information in real time for use in the EEA process. The policy
could ask the BAs to initially review and assess their needs and relay this to their RC. The policy
would be available for re-review if the BA’s performance approaches non-compliance. • The standard
should be based on the lesser of 80% of MSSC, 1000MW, or a lower value chosen by the Balancing
Authority.
Group
Bonneville Power Administration
Jamison Dye
Transmission Reliability Program
No
BPA recommends further clarity and explanation for the sudden unplanned outage of a transmission
facility, and sudden loss of known load used as a resource that causes an unexpected change to
responsible entity’s ACE. BPA also recommends leaving in the failure to start language that has been
removed.
Yes
Yes
Yes

Yes
Yes
Yes
No
BPA recommends changing the VSLs for R2 to: Lower VSL more than 2 but less than or equal to 5
hours; Moderate VSL more than 5 but less than or equal to 10 hours; High VSL more than 10 but less
than or equal to 15 hours; Severe VSL More than 15 hours.
Yes
BPA is in support of this standard.
Individual
Alice Ireland
Xcel Energy
Yes
Yes
If the DCS definition will not be used any longer, recommend the team retire it from the NERC
glossary.
Yes

The drafting team is proposing to continue to use only ACE under Requirement R1 as the measure of
reliability in the determination of Balancing Authority or RSG compliance. As has been seen in actual
operation, the current methodology can lead to and has caused RC directives to drop load when there
was not a reliability issue, defined as a frequency concern or transmission line loading issue. ACE is
not a primary measure of reliability, only equity. Therefore, Xcel Energy is voting against the
proposed standard. To remedy this deficiency in the proposed standard, the drafting team should
utilize the BAAL limit as a more appropriate measure of response to the sudden loss of generation,
not pre-event ACE or zero, whichever is lower. As proposed by Xcel Energy, this does not do away
with DCS as originally proposed under BAAL but would change the measure of compliance in the DCS
process to a more appropriate, reliability based measure. Xcel Energy is also not proposing to change
the 15-minute period in BAL-002 for a reportable event with this modification.

Consideration of Comments
Project 2010-14.1 Phase I of Balancing Authority-based
Controls: Reserves BAL-001-2
The Standard Drafting Team thanks all commenters who submitted comments on the BAL-001-2
standard. There were 55 sets of comments, including comments from approximately 178 different
people from approximately 100 companies representing 8 of the 10 Industry Segments as shown in the
table on the following pages.
Based on industry comments the drafting team made the following clarifying modifications to the
proposed standard and associated documents.
Made clarifying changes to the proposed standard including adding the term “…in accordance
with…” in Requirement R2.
Made clarifying changes to the definition for Reporting ACE.
Modified the effective date to allow for 12 months to prepare for compliance with BAAL.
Corrected typographical errors in all documents.
There were a couple of minority issues that the team was unable to resolve, including the following:
Many stakeholders felt that using BAAL could cause increased inadvertent flows and
transmission issues. The drafting team explained that they had not seen any such issues
described occur during the field trial that could be directly attributable to the use of BAAL.
BAAL was designed to provide for better control by allowing power flows that do not have a
detrimental effect on reliability but restrict those that do have a detrimental effect on
reliability.
A couple of stakeholders were concerned that a small BAs operation could be more restrictive
under BAAL. The drafting team stated that they were aware of the concern identified.
However, the drafting team was attempting to develop a standard that would be applicable to
the entire continent and did not know of any method to distinguish between larger and smaller
BAs.
A few stakeholders questioned the value of creating a Regulation Reserve Sharing Group. The
drafting team explained that they did not want to rule out any tool that could be used to satisfy
compliance within a standard. The drafting team was not mandating that a BA had to
participate in a RRSG but could if it was determined to be in their best interest.
One stakeholder expressed the need for an exemption from compliance during an EEA Level 1,
2, or 3 since they were a single BA Interconnection. The SDT explained that they discussed their
concern but came to the conclusion that they did not believe that granting a exemption from
compliance was in the best interest of reliability.

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

1

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 Vice President and Director of Standards, Mark Lauby, at 404-446-2560 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.1

1

The appeals process is in the Standard Processes Manual: http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

2

Index to Questions, Comments, and Responses
1.

The BARC SDT has developed two new terms to be used with this standard. Regulation Reserve
Sharing Group: A group whose members consist of two or more Balancing Authorities that
collectively maintain, allocate, and supply the regulating reserve required for all member
Balancing Authorities to use in meeting applicable regulating standards. Regulation Reserve
Sharing Group Reporting ACE: At any given time of measurement for the applicable Regulation
Reserve Sharing Group, the algebraic sum of the Reporting ACEs (as calculated at such time of
measurement) of the Balancing Authorities participating in the Regulation Reserve Sharing Group
at the time of measurement. Do you agree with the proposed definitions in this standard? If not,
please explain in the comment area below. ................................................................................. 1312

2.

If you are not in support of this draft standard, what modifications do you believe need to be
made in order for you to support the standard? Please list the issues and your proposed solution
to them. ......................................................................................................................................... 2927

3.

If you have any other comments on BAL-001-2 that you haven’t already mentioned above, please
provide them here:........................................................................................................................ 6460

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

3

Sylvain Clermont

Chris de Graffenried Consolidated Edison Co. of New York, Inc. NPCC 1

Gerry Dunbar

Mike Garton

Peter Yost

Michael Jones

4.

5.

6.

7.

8.

9.

NPCC 5

NPCC 10

NPCC 1

NPCC 2

PSEG Power LLC

11. Christina Koncz

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Hydro One Networks Inc.

10. David Kiguel

National Grid

NPCC 5

NPCC 1

NPCC 1

Consolidated Edison Co. of New York, Inc. NPCC 3

Dominion Resources Services, Inc.

Northeast Power Coordinating Council

Hydro-Quebec TransEnergie

New York Independent System Operator

NPCC 2

Greg Campoli

Independent Electricity System Operator

Carmen Agavriloai

3.

NPCC 10

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

4

5

6

7

8

Registered Ballot Body Segment
9

X

10

Hydro-Quebec TransEnergie

Ontario Power Generation, Inc.

Utility Services

National Grid

New York Power Authority

New Brunswick System Operator

Orange and Rockland Utilities

paul haase

17. Si-Truc Phan

18. David Ramkalawan

19. Brian Robinson

20. Brian Shanahan

21. Wayne Sipperly

22. Donald Weaver

23. Ben Wu

2.

dana wheelock

hao li

mike haynes

dennis sismaet

2.

3.

4.

5.

Russel MountjoySecretary

seattle city light

seattle city light

seattle city light

seattle city light

seattle city light

MRO NERC Standards Review Forum

WECC 6

WECC 5

WECC 4

WECC 3

WECC 1

Joseph DePoorter

Dan Inman

Dave Rudolf

Jodi Jensen

Ken Goldsmith

Lee Kittleson

Marie Knowx

Mike Brytowski

2.

3.

4.

5.

6.

7.

8.

9.

GRE

MISO

OTP

ALTW

WAPA

BEPC

MPC

MGE

Xcel Energy

MRO

MRO

MRO

MRO

MRO

MRO

MRO

MRO

MRO

1, 3, 5, 6

2

1, 3, 5

4

1, 6

1, 3, 5, 6

1, 3, 5, 6

3, 4, 5, 6

1, 3, 5

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Alice Ireland

1.

Additional Member Additional Organization Region Segment Selection

Group

pawel krupa

1.

3.

seattle city light

NPCC 1

NPCC 2

NPCC 5

NPCC 1

NPCC 8

NPCC 5

NPCC 1

Additional Member Additional Organization Region Segment Selection

Group

The United Illuminating Company

16. Robert Pellegrini

NPCC 1

NPCC 10

Northeast Power Coordinating Council

15. Lee Pedowicz

NPCC 6
NPCC 5

New York Power Authority

13. Bruce Metruck

NPCC 9

Organization

14. Silvia Parada Mitchell NExtEra Energy, LLC

New Brunswick Power Transmission

Commenter

12. Randy MacDonald

Group/Individual

X

X

1

2

X

X

3

X

X

4

X

X

5

5

X

X

6

7

8

Registered Ballot Body Segment
9

X

10

MEC

WPS

NPPD

Robert Rhodes

12. Terry Harbour

13. Tom Breene

14. Tony Eddleman

4.

Westar Energy

6. Bryan Taggart

1, 3, 5, 6

1, 3, 5, 6

1

1, 3, 5, 6

1, 3, 5, 6

SERC OC Standards Review Group

SPP

SPP

SPP

David Jendras

Kevin Johnson

Colby Brett Bellville Duke

Mike Lowman

Tom Pruitt

Jim Case

Phil Whitmer

3.

4.

5.

6.

7.

8.

9.

SERC

SERC

SERC

SERC

SERC

SERC

SERC

SERC

MISO

PJM

PowerSouth

Power South

Progress Energy

SCE&G

11. Terry Bilke

12. Brad Gordon

13. Bill Thigpen

14. Tim Hattaway

15. Sammy Roberts

16. Troy Blalock

SERC

SERC

SERC

SERC

SERC

SERC

SERC

1, 3, 5, 6

1, 3, 5, 6

1, 5

1, 5

2

2

1, 3, 5, 6

3

1, 3, 6

1, 3, 5, 6

1, 3, 5, 6

1, 3, 5, 6

1

1, 3

4

1, 3, 5, 6

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

LGE-KU

10. Wayne Van Liere

Georgia Power Company SERC

Enteregy

Duke

Duke

Big Rivers

Ameren

AMEA

Ray Phillips

2.

AECI

Jeff Harrison

1.

Additional Member Additional Organization Region Segment Selection

Stuart Goza

Westar Energy

5. Kevin Nincehelser

Group

Sunflower Electric Power Corporation SPP

4. Jerry McVey

5.

Westar Energy

3. Tiffany Lake

SPP

Westar Energy

2. Bo Jones

1

Region Segment Selection

Sunflower Electric Power Corporation SPP

1. Allan George

Additional Member

1, 3, 5

3, 4, 5, 6

1, 3, 5, 6

4

1, 3, 5, 6

Organization

SPP Standards Review Group

MRO

MRO

MRO

MRO

MRO

Additional Organization

RPU

11. Scott Nickels

Group

MPW

Commenter

10. Scott Bos

Group/Individual

X

1

X

2

X

3

4

X

6

5

X

6

7

8

Registered Ballot Body Segment
9

10

SCPSA

SCPSA

SIPC

Southern

Southern

Southern

Southern

TVA

Greg Rowland

18. Rene Free

19. Tom Abrams

20. John Rembold

21. Cindy Martin

22. Jimmy Cummings

23. Jimmy Cummings

24. Randy Hubbert

25. Kelly Casteel

6.

Duke Energy

Duke Energy

3. Dale Goodwine

4. Greg Cecil

PPL NERC Registered Affiliates

6

5

3

1

Larry Raczkowski

FirstEnergy Solutions

FirstEnergy Solutions

4. Ken Dresner

5. Kevin Querry

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

MRO

1, 6

Region Segment Selection

Western Area Power Administration

6

5

4

3

1

1. Western Area Power Administration Upper Great Plains Region

Additional Member

RFC

RFC

RFC

RFC

RFC

Additional Organization

Ohio Edison

3. Doug Hohlbaugh

Lloyd A. Linke

FirstEnergy Corp

2. Cindy Stewart

Group

FirstEnergy Corp

9.

FirstEnergy

Additional Member Additional Organization Region Segment Selection

Group

1. William Smith

8.

MRO

6

WECC 5

4. Elizabeth Davis

5

1

3.

RFC

PPL Generation, LLC on behalf of Supply NERC Registered Affiliates RFC

2. Annette Bannon

PPL EnergyPlus, LLC

X

X

1

2

X

X

Region Segment Selection

PPL Electric Utilities Corporation

Additional Organization

RFC

SERC

FRCC

RFC

1. Brenda Truhe

Additional Member

Brent Ingebrigtson

Duke Energy

2. Lee Schuster

Group

Duke Energy

1. Doug Hils

7.

1, 4, 5, 6

1, 5

1, 5

1, 5

1, 5

1

1, 3, 5, 6

1, 3, 5, 6

1, 3, 5, 6

Duke Energy

SERC

SERC

SERC

SERC

SERC

SERC

SERC

SERC

SERC

Organization

Additional Member Additional Organization Region Segment Selection

Group

SCPSA

Commenter

17. Glenn Stephens

Group/Individual

X

X

X

3

X

4

X

X

X

7

5

X

X

X

X

6

7

8

Registered Ballot Body Segment
9

10

WECC 1, 6

4. Western Area Power Administration Sierra Nevada Region

Group

Marie Knox

MISO Standards Collaborators

Group

H. Steven Myers

NIPSCO

RFC

ERCOT

6

ERCOT

ERCOT

ERCOT

ERCOT

4. Ken McIntyre

5. Stephen Solis

6. Vann Weldon

7. Jeff Healy

Dennis Chastain

1, 3, 5, 6

Tennessee Valley Authority

MRO

SERC

4. Marjorie Parsons

Oklahoma Gas & Electric

6

5

3

1

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Additional Member Additional Organization Region Segment Selection

Terri Pyle

SERC

3. David Thompson

Group

SERC

2. Ian Grant

14.

SERC

1. DeWayne Scott

Additional Member Additional Organization Region Segment Selection

Group

Great River Energy

4. Michael Brytowski

13.

Southwest Transmission Cooperative WECC 1

3. John Shaver

WECC 4, 5

Arizona Electric Power Cooperative

2. John Shaver

1

Region Segment Selection

Sunflower Electric Power Corporation SPP

Additional Organization

ACES Standards Collaborators

ERCOT 2

ERCOT 2

ERCOT 2

ERCOT 2

ERCOT 2

ERCOT 2

ERCOT 2

1. Megan Wagner

Additional Member

Jason Marshall

ERCOT

3. Matt Stout

Group

ERCOT

2. Sandip Sharma

12.

ERCOT

1. Matt Morais

Additional Member Additional Organization Region Segment Selection

11.

1. Joe O'Brein

Additional Member Additional Organization Region Segment Selection

10.

5. Western Area Power Administration Colorado River Storage Project WECC 6

WECC 1, 6

3. Western Area Power Administration Desert Southwest Region

Organization

WECC 1, 6

Commenter

2. Western Area Power Administration Rocky Mouontain Region

Group/Individual

X

X

1

X

X

2

X

X

3

4

X

X

8

5

X

X

6

7

8

Registered Ballot Body Segment
9

10

Additional Member

Group

Region Segment Selection

Terry Bilke

IRC-SRC

Luminant Generation Company LLC ERCOT 5

Additional Organization

Luminant

5

3

1

Organization

2

Region Segment Selection

BC Hydro and Power Authority

Additional Organization

Patricia Robertson

Additional Member

Group

WECC 2

Jamison Dye

Bonneville Power Administration

WECC 5
WECC 1

5. Pam VanCalcar

6. Don Watkins

21.

20.

Individual

Individual

PacifiCorp

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Ryan Millard

Arizona Public Service Company

Salt River Project

WECC 1

4. Ayodele Idowu

Bob Steiger
Janet Smith, Regulatory
Affairs Supervisor

WECC 1

3. David Kirsch

Individual

WECC 5

2. Fran Halpin

19.

WECC 1

1. Bart McManus

Additional Member Additional Organization Region Segment Selection

Group

BC Hydro and Power Authority WECC 5

3. Clement Ma

18.

BC Hydro and Power Authority WECC 3

2. Pat G. Harrington

1. Venkataramakrishnan Vinnakota BC Hydro and Power Authority WECC 2

17.

CAISO

5. Ali Miremadi

2

SPP

SPP

4. Charles Yeung

NPCC 2

RFC
NPCC 2

IESO

2. Ben Li

3. Kathleen Goodman ISONE

PJM

1. Stephanie Monzon

Additional Member Additional Organization Region Segment Selection

16.

1. Rick Terrill

Brenda Hampton

Oklahoma Gas & Electric SPP

3. Leo Staples

Group

Oklahoma Gas & Electric SPP

2. Donald Hargrove

15.

Oklahoma Gas & Electric SPP

Commenter

1. Terri Pyle

Group/Individual

X

X

X

X

X

1

X

X

2

X

X

X

X

X

3

4

X

X

X

X

X

9

5

X

X

X

X

X

6

7

8

Registered Ballot Body Segment
9

10

Individual

Individual

Individual

Individual

Individual

Individual

Individual

Individual

Individual

Individual

Individual

Individual

Individual

Individual

Individual

Individual

Individual

Individual

Individual

Individual

25.

26.

27.

28.

29.

30.

31.

32.

33.

34.

35.

36.

37.

38.

39.

40.

41.

42.

43.

Individual

Individual

24.

23.

22.

Don Jones

Linda Horn

John Seelke

Thad Ness

Kathleen Goodman

Angela P Gaines

Andrew Gallo

Kenneth A Goldsmith

Don Schmit

Howard F. Illian

Michael Falvo

Greg Travis

Jim Cyrulewski

Joe Tarantino

Anthony Jablonski

Nazra Gladu

Rich Hydzik

John Tolo

Tom Siegrist

Dan O'Hearn

Pamela R. Hunter

Stephanie Monzon

Commenter

Organization

Texas Reliability Entity

Wisconsin Electric Power Company

Public Service Enterprise Group

American Electric Power

ISO New England Inc.

Portland General Electric Company

City of Austin dba Austin Energy

Alliant Energy

Nebraska Public Power District

Energy Mark, Inc.

Independent Electricity System Operator

Idaho Power Company

JDRJC Associates LLC

SMUD

ReliabilityFirst

Manitoba Hydro

Avista

Tucson Electric Power Co

EnerVision, Inc.

Powerex Corp.

PJM Interconnection, L.L.C
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

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Group/Individual

X

X

X

X

X

X

X

X

X

X

X

X

1

X

X

2

X

X

X

X

X

X

X

X

X

X

X

3

X

X

X

X

4

X

X

X

X

X

X

X

X

X

X

10

5

X

X

X

X

X

X

X

X

6

X

7

X

8

Registered Ballot Body Segment
9

X

X

10

Individual

Individual

Individual

50.

51.

52.

Individual

Individual

54.

55.

Individual

Individual

49.

53.

Individual

48.

Organization

Xcel Energy

Tacoma Power

Exelon

NYISO

Modesto Irrigation District

Platte River Power Authority

City of Tallahassee

City of Tallahassee

City of Tallahassee

NextEra Energy
Keen Resources Ltd.

Entergy Services, Inc. (Transmission)

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Alice Ireland

Keith Morisette

Gregory Campoli
John Bee on Behalf or
Exelon and its Affiliates

Spencer Tacke

Christopher Wood

Scott Langston

Karen Webb

Bill Fowler

Individual

47.

Oliver Burke

Brian Murphy
Robert Blohm

Individual

Commenter

Individual
46. Individual

45.

44.

Group/Individual

X

X

X

X

X

X

X

1

X

2

X

X

X

X

X

X

X

X

3

X

X

4

X

X

X

X

X

X

X

11

5

X

X

X

X

X

X

6

7

X

8

Registered Ballot Body Segment
9

10

ERCOT
Midwest ISO
Midwest ISO
MISO
MRO NSRF
Northeast Power Coordinating Council
PJM Interconnection
Public Service Company of Colorado (Xcel Energy)
SERC OC Standards Review Group
SERC OC Standards Review Group

City of Austin dba Austin Energy

JDRJC Associates LLC

Wisconsin Electric Power Company

FirstEnergy

Alliant Energy

NYISO

Public Service Enterprise Group

Platte River Power Authority

Tennessee Valley Authority

Entergy Services, Inc. (Transmission)

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Electric Reliability Council of Texas (ERCOT)

12

Supporting Comments of “Entity Name”

Luminant

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).

The BARC SDT has developed two new terms to be used with this standard. Regulation Reserve Sharing Group: A group whose
members consist of two or more Balancing Authorities that collectively maintain, allocate, and supply the regulating reserve
required for all member Balancing Authorities to use in meeting applicable regulating standards. Regulation Reserve Sharing
Group Reporting ACE: At any given time of measurement for the applicable Regulation Reserve Sharing Group, the algebraic
sum of the Reporting ACEs (as calculated at such time of measurement) of the Balancing Authorities participating in the
Regulation Reserve Sharing Group at the time of measurement. Do you agree with the proposed definitions in this standard? If
not, please explain in the comment area below.

No

Yes or No

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

ACES Standards Collaborators

Organization

13

(1) How does this standard “specifically preclude general improvements

Question 1 Comment

The majority of the commenters provided typographical corrections that needed to be made to the standard and its associated
documents.

Some commenters stated that the Regulating Reserve Sharing Group was not in either the Functional Model or any NERC registry.
The SDT explained that the Regulating Reserve Sharing Group would be added to the NERC Compliance Registry prior
to implementation of this standard.

Several commenters questioned the need to create a definition for Reporting ACE. The SDT stated that the intent was to create a
standard term for ACE that was flexible enough to not require development of a regional standard. The SDT has
chosen not to include a generic time error correction term in the Reporting ACE equation definition. The SDT has
modified the definition to address concerns raised by the industry.

Summary Consideration: Many of the commenters expressed concern that creating a Regulating Reserve Sharing Group conflicted
with Reserve Sharing Group or was not clear in its use. The SDT explained that Reserve Sharing Group is already a
defined term in the NERC Glossary (for contingency reserve sharing). The SDT was proposing to add a definition that
applies to regulating reserve sharing. The SDT appreciates your comments, and has added language to the Background
Document to provide clarity. In addition, the SDT is not mandating that a BA has to participate in a RRSG but could if it
was determined to be in their best interest. The SDT is simply providing an additional tool for BAs to use and did not
want to rule out any tool that could be used to satisfy compliance within a standard.

1.

Organization

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Yes or No

14

to PRC-005-2”? By introducing a new project for PRC-005, the entire
standard is subject to revision. The previous standard could be
modified and there are no scope restrictions to this project under the
NERC Rules of Procedure. There is nothing to preclude changes to
Protection Systems. The drafting team should be aware of these
implications and reconsider the development of this project, as the last
draft took almost seven years to gain industry approval. Further, the
Commission has not even ruled on the pending standard, so there is still
a tremendous amount of uncertainty as to whether any additional
directives or modifications need to be made to PRC-005-2.(2) We have
serious concerns with the new definitions being proposed in this draft
standard. We feel this excessiveness terms are unnecessary when the
standard is only adding a new type of device to an entity’s existing
maintenance and testing procedure.(3) For example, the “Auto
Reclosing” definition is vague and requires further interpretation. What
does “such as anti-pump and ‘various’ interlock circuits” mean?
“Various” is not a clear adjective to describe interlock circuits. We
recommend revising the entire definition to clearly state the scope of
the devices, or better yet, strike the definition from the standard.(4)
The term “unresolved maintenance issue” is plain language with a
common meaning, and therefore does not need to be introduced as a
defined glossary term. This definition could lead to more zero defect
compliance and enforcement treatment. What happens if a
maintenance issue is not identified as unresolved? Shouldn’t a
registered entity’s internal controls address these issues? Also, this
term is missing the other half of the standard - the testing of these
devices. It’s possible to have an unresolved testing issue as well. (5)
The Commission set limitations on the autoreclosing devices that
should be included in Order No. 758. An autoreclosing relay should be
tested and maintained, “if it either is used [1] in coordination with a
Protection System to achieve or meet system performance

Question 1 Comment

Organization

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Yes or No

15

requirements established in other Commission-approved Reliability
Standards, or [2] can exacerbate fault conditions when not properly
maintained and coordinated, then excluding the maintenance and
testing of these reclosing relays will result in a gap in the maintenance
and testing of relays affecting the reliability of the Bulk-Power System.”
This is problematic because the primary purpose of reclosing relays is to
allow more expeditious restoration of lost components of the system,
not to maintain the reliability of the Bulk-Power System. This standard
would improperly include many types of reclosing relays that do not
necessarily affect the reliability of the Bulk-Power System.(6) Order No.
758 (P. 26), the Commission stated that “the standard should be
modified, through the Reliability Standards development process, to
provide the Transmission Owner, Generator Owner, and Distribution
Provider with the discretion to include in a Protection System
maintenance and testing program only those reclosing relays that the
entity identifies as having an affect on the reliability of the Bulk-Power
System.” (7) There are concerns with the supplementary reference
document because it assumes that PRC-005-2 will be approved by the
Commission. This assumption is misleading and should not reflect any
Commission rulings that have yet to occur. We recommend stating the
current status of the PRC-005-2 project, which was filed with FERC in
February 2013 and is pending the Commission’s approval. Statements
such as “PRC-005-2 ‘replaced’ PRC-011” should be modified to “PRC005-2 will replace PRC-011 upon approval from FERC,” or something
similar. (8) The drafting team stated that it reviewed the NERC System
Analysis and Modeling Subcommittee (SAMS) “Considerations for
Maintenance and Testing of Autoreclosing Schemes - November 2012.”
SAMS concluded that automatic reclosing is largely implemented
throughout the BES as an operating convenience, and that automatic
reclosing mal†performance affects BES reliability only when the
reclosing is part of a Special Protection System, or when inadvertent

Question 1 Comment

Yes or No

reclosing near a generating station subjects the generation station to
severe fault stresses. This report is concluding that these devices do
not result in a gap and do not affect the reliability of the Bulk†Power
System, unless very specific circumstances arise as in the instance
where reclosing relays are a part of an SPS scheme. This technical
document does not support the development of the standard; rather,
the report refutes the need to include these devices in the standard’s
applicability.

Question 1 Comment

Duke Energy

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

No

16

Duke Energy agrees that special provisions may be necessary to capture
the combined BAAL performance of two BAs operating under a
Supplemental Regulation agreement so that one BA can’t reset the 30minute compliance clock of the other BA with a change to the dynamic
interchange; however, we are concerned that these definitions could be
interpreted to mean that three or more BAs could operate as one,
sharing regulation, while the Standards lack sufficient detail behind how
the associated interchange of such a group would be tagged or
otherwise captured to ensure that the transmission impact is evaluated
and subject to curtailment similar to other interchange. When a BA is
formed from multiple BAs, its anticipated operation, impact on
neighboring systems, and readiness to operate are evaluated - in some
cases seams agreements have been required to address adjacent
system concerns. The idea that multiple BAs could get together and
form a Regulation Reserve Sharing Group (with the potential to impact
neighboring systems no differently than is a single BA) without such
scrutiny could have reliability implications. Regulation Reserve Sharing
Group is not currently included in the NERC Functional Model. The
process for registering such a group would have to be addressed for
compliance. The words “regulating reserve” should be capitalized in the

Response: The BARC standards drafting team believes that this answer does not apply to the proposed BAL-001-2 standard.

Organization

Yes or No
definition of RRSG.

Question 1 Comment

No

It is not clear what exact intent the drafting team has in the
introduction of the term “Regulation Reserve Sharing Group”. This term
is specified in the Applicability section, so is it the drafting team’s intent
to propose that this new term be established as a new Functional
Entity? If that is not the intent, we believe it is mistaken to specify any
applicability to any grouping that does not have formal, registered
members.

No

PJM disagrees with the Interconnection specific inclusion of IATEC in
the Reporting ACE definition. The definition of ACE is internationally
recognized. It is inappropriate for the SDT to change that definition
because of one region in North America. PJM believes all
Interconnections should adhere to a common ACE equation definition
and that Interconnection specific differences should be addressed
through development of a regional standard, as was BAL-004-WECC-01.

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

17

Response: The SDT appreciates your comments. The intent was to create a standard term for ACE that was flexible enough to

PJM Interconnection, L.L.C

Response: Reserve Sharing Group is already a defined term in the NERC Glossary (for contingency reserve sharing). The SDT was
proposing to add a definition that applies to regulating reserve sharing. The SDT appreciates your comments, and has added
language to the Background Document to provide clarity. In addition, the SDT is not mandating that a BA has to participate in a
RRSG but could if it was determined to be in their best interest. The SDT is simply providing an additional tool for BAs to use
and did not want to rule out any tool that could be used to satisfy compliance within a standard.

American Electric Power

Response: Reserve Sharing Group is already a defined term in the NERC Glossary (for contingency reserve sharing). The SDT was
proposing to add a definition that applies to regulating reserve sharing. The SDT appreciates your comments, and has added
language to the Background Document to provide clarity. In addition, the SDT is not mandating that a BA has to participate in a
RRSG but could if it was determined to be in their best interest. The SDT is simply providing an additional tool for BAs to use
and did not want to rule out any tool that could be used to satisfy compliance within a standard.

Organization

Yes or No

Question 1 Comment

No

The definition of Regulation Reserve Sharing Group (RRSG) does not
match the Applicability section. The above definition states that the
pooled regulating reserves are used by the member balancing
authorities to meet applicable regulating standards. I don’t think this is
technically correct. The balancing authority that is a member of an
RRSG basically transfers its obligations to the RSSG as Responsible
Entity. The BA is only the Responsible Entity during periods where they
are not in active status with the RRSG. Suggested rewording: End the
sentence after the second occurrence of “Balancing Authorities” and
delete “to use in meeting applicable regulating standards”. This may be
sufficient but would probably be better if the following were added to
the end: “When Balancing Authorities which are in active status and
operating under the rules of an RRSG, the RRSG becomes the
Responsible Entity for Standard Requirements related to Regulating
Reserves for the member Balancing Authorities.

No

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Northeast Power Coordinating Council

18

The need to create the two new terms (RRSG and RRSG Reporting ACE)
and the applicability exceptions for BAs that receives overlap regulation
service or participate in the RRSG is not apparent. The Standard should
stipulate the requirements for each BA to meet the CPS1 and BAAL
requirements only, regardless of how it arranges for the regulation
services to meet these requirements. Suggest removing the two new

Response: Reserve Sharing Group is already a defined term in the NERC Glossary (for contingency reserve sharing). The SDT was
proposing to add a definition that applies to regulating reserve sharing. The SDT appreciates your comments, and has added
language to the Background Document to provide clarity. In addition, the SDT is not mandating that a BA has to participate in a
RRSG but could if it was determined to be in their best interest. The SDT is simply providing an additional tool for BAs to use
and did not want to rule out any tool that could be used to satisfy compliance within a standard.

Bonneville Power Administration

not require development of a regional standard. The SDT has chosen not to include a generic time error correction term in the
Reporting ACE equation definition. The SDT has modified the definition to address concerns raised by the industry.

Organization

Yes or No

terms, and the applicability exception for BAs receiving overlap
regulation service or participating in the RRSG. The current posted
version appears to place requirements on both individual BAs and the
RRSG, but the obligations for the latter are not clearly stipulated in the
Standard. There is no need to have the latter (RRSG) requirements
stipulated for the RRSG so long as the Standard places the obligation to
each BA to meet the CPS1 and BAAL requirements. The first term
(RRSG) is used in the Applicability section and should be used in R1.
However, the proposed Standard allows for overlap and supplemental
regulation and hence a BA may obtain regulation services through these
mechanisms only; there is no requirement for the RRSG to comply with
group CPS1 or report RRSG ACE in the Standard, nor is the RRSG
Reporting ACE calculation depicted in the Attachments. We suggest
removing these new terms. The term “RRSG” is used in the Applicability
section of the Standard and concern was raised about continued use of
new terms not specifically in the Functional Model, along with any
specific tasks and roles for these newly defined “entities”. Should the
Functional Model Working Group (FMWG) review the proposed
definition and consider the RRSG as an addition for the NERC Version 6
of the Functional Model? We suggest that NERC set up a process
whereby all proposals for newly defined entities be vetted and cleared
through the FMWG.

Question 1 Comment

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

19

Response: The SDT appreciates your comments. Reserve Sharing Group is already a defined term in the NERC Glossary (for
contingency reserve sharing). The SDT was proposing to add a definition that applies to regulating reserve sharing. The SDT
appreciates your comments, and has added language to the Background Document to provide clarity. In addition, the SDT is not
mandating that a BA has to participate in a RRSG but could if it was determined to be in their best interest. The SDT is simply
providing an additional tool for BAs to use and did not want to rule out any tool that could be used to satisfy compliance within
a standard. The intent was to create a standard term for ACE that was flexible enough to not require development of a regional
standard. The SDT has chosen not to include a generic time error correction term in the Reporting ACE equation definition. The

Organization

Yes or No

Question 1 Comment

No

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

ISO New England Inc.

20

The need to create the two new terms (RRSG and RRSG Reporting ACE)
and the applicability exceptions for BAs that receives overlap regulation
service or participate in the RRSG is not apparent. The Standard should
stipulate the requirements for each BA to meet the CPS1 and BAAL
requirements only, regardless of how it arranges for the regulation
services to meet these requirements. Suggest removing the two new
terms, and the applicability exception for BAs receiving overlap
regulation service or participating in the RRSG. The current posted
version appears to place requirements on both individual BAs and the
RRSG, but the obligations for the latter are not clearly stipulated in the
Standard. There is no need to have the latter (RRSG) requirements
stipulated for the RRSG so long as the Standard places the obligation to
each BA to meet the CPS1 and BAAL requirements. The first term
(RRSG) is used in the Applicability section and should be used in R1.
However, the proposed Standard allows for overlap and supplemental
regulation and hence a BA may obtain regulation services through these
mechanisms only; there is no requirement for the RRSG to comply with
group CPS1 or report RRSG ACE in the Standard, nor is the RRSG
Reporting ACE calculation depicted in the Attachments. We suggest
removing these new terms. The term “RRSG” is used in the Applicability
section of the Standard and concern was raised about continued use of
new terms not specifically in the Functional Model, along with any
specific tasks and roles for these newly defined “entities”. Should the
Functional Model Working Group (FMWG) review the proposed
definition and consider the RRSG as an addition for the NERC Version 6
of the Functional Model? We suggest that NERC set up a process
whereby all proposals for newly defined entities be vetted and cleared

The Regulating Reserve Sharing Group will be added to the NERC Compliance Registry prior to this standard becoming effective.

SDT has modified the definition to address concerns raised by the industry.

Organization

Yes or No
through the FMWG.

Question 1 Comment

No

The proposed definitions have not been adequately justified for
inclusion in the standard. The background document does not provide
any additional information or reasons for inclusion of these definitions.

No

This concept violates the very definition of a balancing authority
(control area).

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

21

Response: The SDT appreciates your comments. Unfortunately, the SDT would need additional information to provide a
response to your comment.

Modesto Irrigation District

Reserve Sharing Group is already a defined term in the NERC Glossary (for contingency reserve sharing). The SDT was proposing
to add a definition that applies to regulating reserve sharing. The SDT appreciates your comments, and has added language to
the Background Document to provide clarity. In addition, the SDT is not mandating that a BA has to participate in a RRSG but
could if it was determined to be in their best interest. The SDT is simply providing an additional tool for BAs to use and did not
want to rule out any tool that could be used to satisfy compliance within a standard.

The intent was to create a standard term for ACE that was flexible enough to not require development of a regional standard.
The SDT has chosen not to include a generic time error correction term in the Reporting ACE equation definition. The SDT has
modified the definition to address concerns raised by the industry.

Response: The SDT appreciates your comments. The SDT has developed these terms for the following reasons.

Powerex Corp.

The Regulating Reserve Sharing Group will be added to the NERC Compliance Registry prior to this standard becoming effective.

The intent was to create a standard term for ACE that was flexible enough to not require development of a regional standard.
The SDT has chosen not to include a generic time error correction term in the Reporting ACE equation definition. The SDT has
modified the definition to address concerns raised by the industry.

Response: The SDT appreciates your comments. Reserve Sharing Group is already a defined term in the NERC Glossary (for
contingency reserve sharing). The SDT was proposing to add a definition that applies to regulating reserve sharing. The SDT
appreciates your comments, and has added language to the Background Document to provide clarity.

Organization

No

Yes or No

We do not see the need to create these terms. We understand that the
first term (RRSG) is used in the applicability section and arguable in R1.
However, the proposed standard allows for overlap and supplemental
regulation and hence a BA may obtain regulation services through these
mechanisms only; there is no requirement for the RRSG to comply with
group CPS1 or report RRSG ACE in the standard, nor is the RRSG
Reporting ACE calculation depicted in the Attachments. We suggest
removing these new terms. Furthermore, since the term RRSG is in the
applicability section of the standard, it implies that this is a new
functional entity. In order for this term to have applicability, it needs to
have defined roles. This definition should be vetted through the
functional model working group and included in the functional model
PRIOR to being included in BAL-001.

Question 1 Comment

No

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

MRO NERC Standards Review Forum

22

We don’t understand the reasoning for these new definitions.
Balancing Authorities have an Area Control Error. The standards
presently allow for overlap and supplemental regulation that allow a BA
to obtain regulation services, which appears to be the driver for these
definitions. We also cannot find in a SAR associated with this project
that proposes to change BAL-001. While the Reliability Based Control

The Regulating Reserve Sharing Group will be added to the NERC Compliance Registry prior to this standard becoming effective.

The intent was to create a standard term for ACE that was flexible enough to not require development of a regional standard.
The SDT has chosen not to include a generic time error correction term in the Reporting ACE equation definition. The SDT has
modified the definition to address concerns raised by the industry.

Response: Reserve Sharing Group is already a defined term in the NERC Glossary (for contingency reserve sharing). The SDT was
proposing to add a definition that applies to regulating reserve sharing. The SDT appreciates your comments, and has added
language to the Background Document to provide clarity. In addition, the SDT is not mandating that a BA has to participate in a
RRSG but could if it was determined to be in their best interest. The SDT is simply providing an additional tool for BAs to use
and did not want to rule out any tool that could be used to satisfy compliance within a standard.

Independent Electricity System
Operator

Organization

Yes or No

standard is referenced in the changes, RBC deals with a 30 minute limit
on ACE and not redefinition of ACE and the creation of new entities.

Question 1 Comment

No

We don’t understand the reasoning for these new definitions.
Balancing Authorities have an Area Control Error. The standards
presently allow for overlap and supplemental regulation that allow a BA
to obtain regulation services, which appears to be the driver for these
definitions. We also cannot find in a SAR associated with this project
that proposes to change BAL-001. While the Reliability Based Control
standard is referenced in the changes, RBC deals with a 30 minute limit
on ACE and not redefinition of ACE and the creation of new entities.

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

23

Response: The SDT appreciates your comments. Reserve Sharing Group is already a defined term in the NERC Glossary (for
contingency reserve sharing). The SDT was proposing to add a definition that applies to regulating reserve sharing. The SDT
appreciates your comments, and has added language to the Background Document to provide clarity. In addition, the SDT is not
mandating that a BA has to participate in a RRSG but could if it was determined to be in their best interest. The SDT is simply
providing an additional tool for BAs to use and did not want to rule out any tool that could be used to satisfy compliance within

MISO Standards Collaborators

The Regulating Reserve Sharing Group will be added to the NERC Compliance Registry prior to this standard becoming effective.

The SDT is not attempting to redefine ACE. The intent was to create a standard term for ACE that was flexible enough to not
require development of a regional standard. The SDT has chosen not to include a generic time error correction term in the
Reporting ACE equation definition. The SDT has modified the definition to address concerns raised by the industry. In addition,
the SDT is proposing to move the definition out of the BAL-001 standard and into the NERC Glossary as they feel it applies to
multiple standards.

Response: The SDT appreciates your comments. Reserve Sharing Group is already a defined term in the NERC Glossary (for
contingency reserve sharing). The SDT was proposing to add a definition that applies to regulating reserve sharing. The SDT
appreciates your comments, and has added language to the Background Document to provide clarity. In addition, the SDT is not
mandating that a BA has to participate in a RRSG but could if it was determined to be in their best interest. The SDT is simply
providing an additional tool for BAs to use and did not want to rule out any tool that could be used to satisfy compliance within
a standard.

Organization

Yes or No

Question 1 Comment

No

We don’t understand the reasoning for these new definitions.
Balancing Authorities have an Area Control Error. The standards
presently allow for overlap and supplemental regulation that allow a BA
to obtain regulation services, which appears to be the driver for these
definitions. We also cannot find in a SAR associated with this project
the need to change the definitions.

SMUD

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

No

24

While the definitions are acceptable, terminology within the standards

The Regulating Reserve Sharing Group will be added to the NERC Compliance Registry prior to this standard becoming effective.

The SDT is not attempting to redefine ACE. The intent was to create a standard term for ACE that was flexible enough to not
require development of a regional standard. The SDT has chosen not to include a generic time error correction term in the
Reporting ACE equation definition. The SDT has modified the definition to address concerns raised by the industry. In addition,
the SDT is proposing to move the definition out of the BAL-001 standard and into the NERC Glossary as they feel it applies to
multiple standards.

Response: The SDT appreciates your comments. Reserve Sharing Group is already a defined term in the NERC Glossary (for
contingency reserve sharing). The SDT was proposing to add a definition that applies to regulating reserve sharing. The SDT
appreciates your comments, and has added language to the Background Document to provide clarity. In addition, the SDT is not
mandating that a BA has to participate in a RRSG but could if it was determined to be in their best interest. The SDT is simply
providing an additional tool for BAs to use and did not want to rule out any tool that could be used to satisfy compliance within
a standard.

IRC-SRC

The Regulating Reserve Sharing Group will be added to the NERC Compliance Registry prior to this standard becoming effective.

The SDT is not attempting to redefine ACE. The intent was to create a standard term for ACE that was flexible enough to not
require development of a regional standard. The SDT has chosen not to include a generic time error correction term in the
Reporting ACE equation definition. The SDT has modified the definition to address concerns raised by the industry. In addition,
the SDT is proposing to move the definition out of the BAL-001 standard and into the NERC Glossary as they feel it applies to
multiple standards.

a standard.

Organization

Yes or No

that call these discrete entities would be better identified as an
overarching Reserve Sharing Group that would encompass the various
terms: RRSG, RRSGRA ect. Recommend replacing all unique
terminology to only include the Reserve Sharing Group in the BAL-001.

Question 1 Comment

Yes

2) The Regulation Reserve Sharing Group Reporting ACE definition is
different here than the Reserve Sharing Group Reporting ACE definition
provided in BAL-002-which is correct? (Note “at the time of
measurement” as last part of sentence)

1) The equation in the definition of Reporting ACE in the Standard is
different than the one in the Implementation Plan (left off the WECC
ATEC).

Yes

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Manitoba Hydro

25

(2) NIS (Scheduled Net Interchange) - capitalize the word ‘tie lines’

(1) NIA (Actual Net Interchange) - capitalize the word ‘tie lines’ because
it appears in the Glossary of Terms.

Although Manitoba Hydro agrees with the definitions, we have the
following suggestions:

2) The SDT has corrected this and is now using a single term.

1) The SDT has corrected this error.

Response: The SDT appreciates your comments.

Texas Reliability Entity

Response: The SDT appreciates your comments. Reserve Sharing Group is already a defined term in the NERC Glossary (for
contingency reserve sharing). The SDT was proposing to add a definition that applies to regulating reserve sharing. The SDT
appreciates your comments, and has added language to the Background Document to provide clarity. In addition, the SDT is not
mandating that a BA has to participate in a RRSG but could if it was determined to be in their best interest. The SDT is simply
providing an additional tool for BAs to use and did not want to rule out any tool that could be used to satisfy compliance within
a standard.

Organization

1)
2)
3)
4)
5)
6)

Yes or No

(9) PIIaccum - capitalize the words ‘interconnection’, ‘net interchange
schedules’, ‘net interchange’, and ‘scheduled frequency’.

(8) H - de-capitalize ‘Hours’ or is this a Clock Hour?

(7) IATEC (Automatic Time Error Correction) - capitalize the word
interconnection’.

(6) IME (Interchange Meter Error) - the words ‘net interchange actual
(NIA)’ should be re-written as ‘Net Actual Interchange’ and capitalized.
Also, de-capitalize the last instance of ‘Interchange’.

(5) 10 - capitalize ‘frequency bias setting’.

(4) Reporting ACE - capitalize the word ‘net actual interchange’. Also,
add ‘net’ to ‘scheduled interchange’ and capitalize, because definitions
appear in the Glossary of Terms.

(3) Regulation Reserve Sharing Group - capitalize the word ‘regulatingreserve’ because it appears in the Glossary of Terms. Also, the ‘-’
should be removed from ‘regulating-reserve’.

because it appears in the Glossary of Terms. Also, the words ‘Net
Interchange Actual’ should be rewritten as ‘Net Actual Interchange’ and
the word ‘Interchange’ de-capitalized in ‘scheduled Interchange’.

Question 1 Comment

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

26

The SDT has made the correction that you have identified.
The SDT has made the correction that you have identified.
The SDT has made the correction that you have identified.
The SDT has made the correction that you have identified.
The SDT has made the correction that you have identified.
The SDT is purposely using “Net Interchange Actual” per the definition shown in the standard. The SDT has corrected the
interchange.

Response: Thank you for your comments.

Organization

Yes or No

Yes

There are differing references to Regulating Reserve Sharing Group and
Reserve Sharing Group between BAL-001-2 and BAL-002-2. Seattle City
Light recommends consistent terminology across the Standards.

Question 1 Comment

Yes

We are concerned that the term “Reporting ACE” used in this definition
has a different historic meaning than what is being formalized in this
proposed standard. We recommend labeling this term as “Regulation
Reporting ACE.”

Yes
Yes
Yes
Yes
Yes
Yes

PPL NERC Registered Affiliates

ERCOT

Oklahoma Gas & Electric

Salt River Project

Arizona Public Service Company

PacifiCorp

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Yes

SPP Standards Review Group

27

Response: The SDT appreciates your comments. The SDT is trying to provide a consistent measure of ACE to apply across all
standards.

SERC OC Standards Review Group

Response: The SDT appreciates your comments. The SDT has corrected this and is now using a single term.

seattle city light

7) The SDT has made the correction that you have identified.
8) The SDT has made the correction that you have identified.
9) The SDT has made the correction that you have identified.

Organization

Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes

Tucson Electric Power Co

Avista

Idaho Power Company

Energy Mark, Inc.

Portland General Electric Company

Keen Resources Ltd.

City of Tallahassee

City of Tallahassee

City of Tallahassee

Tacoma Power

Xcel Energy

Yes or No

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Yes

EnerVision, Inc.

Southern Company: Southern
Yes
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

Question 1 Comment

28

If you are not in support of this draft standard, what modifications do you believe need to be made in order for you to support
the standard? Please list the issues and your proposed solution to them.

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

29

A few commenters expressed concern that the use of BAAL benefited larger users. The SDT explained that they were unable to
determine whether the difference between BAAL and CPS2 limits is due to: 1) BAAL inappropriately discriminating
against small BAs; or, 2) CPS2 inappropriately favoring small BAs. However, the BARC SDT was able to determine that

Many commenters stated that there were unscheduled flow that created imbalances going in to a BAs ACE and Inadvertent
Interchange Balances. The SDT responded that unscheduled energy flows that do not cause reliability problems are
not reliability issues. Since these issues are not reliability problems they should not be resolved by a reliability
standard. The BAAL Field Trial has provided new information concerning the determination of the contribution of
unscheduled energy to transmission reliability. However, the BARC SDT determined that it was beyond their scope to
take action to implement changes in standards or procedures to restrict the effects of unscheduled energy flows on
transmission loading.

Some commenters felt that this standard was moving in the wrong direction and actually relaxing control performance. The SDT
stated that the appropriate goal for NERC in standards development should not only be to improve reliability, it should
also be to set reliability levels such that the additional value of improved reliability is more than the additional cost of
achieving that reliability improvement. If this is the case then there may be times when the value of reducing
reliability is less than the savings resulting from reduced reliability. Taking any other view will result in inappropriate
reliability decisions for the customers. The SDT further explained that they were focusing in on one of the measures of
reliability which is frequency. Both user’s and supplier’s equipment are designed to operate in a safe frequency range.
By focusing on frequency we provide the ability to meet this reliability goal.

Summary Consideration: Several commenters did not believe that the field trial had produced any positive results and that the
Western Interconnection was experiencing problems associated with the use of BAAL. The SDT explained that BAAL
had been under Field Trial since July 2005 on the Eastern Interconnection, January 2010 in ERCOT, March 2010 on the
Western Interconnection, and January 2011 in Quebec. Voluntary field trials are only as good as the willingness of the
participants. NERC cannot force BAs to participate. The Standard Drafting Team feels that a Field Trial with a duration
approaching eight years should be sufficient to evaluate a standard. Concerning the Field Trial on the Western
Interconnection, the WECC has chosen to take local responsibility for its evaluation and consequently only shared
limited data with NERC. The reports supplied by the WECC have indicated that there are still unknowns associated
with the standard, but they have failed to indicate any significant reliability impacts that can be attributed to the BAAL.

2.

No

Yes or No

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

ACES Standards Collaborators

Organization

30

(1) The SDT needs to clarify the implementation plan. The document is
confusing because it focuses on the PRC-005-2 standard, which is not yet
FERC-approved. This implementation plan is a constantly changing
moving target. Why not wait until PRC-005-2 gets approved before
initiating another project for the same standard? This would reduce
some of the timing issues and confusion.(2) Why is the drafting team
revising a standard that has not been approved by the Commission yet?
The second version was only filed in February 2013, and the timing of
this project is premature. It is quite possible that the Commission could
remand or revise parts of the standard and issue other directives

Question 2 Comment

A few commenters felt that creating a Regulating Reserve Sharing Group provided no benefit. The SDT explained that the SDT was
not mandating that a BA had to participate in a RRSG but could if it was determined to be in their best interest. The
SDT is simply providing an additional tool for BAs to use and did not want to rule out any tool that could be used to
satisfy compliance within a standard.

A couple of commenters did not feel that the six month window prior to implementation of BAAL would allow sufficient time to
prepare. The SDT stated that they agreed and modified the effective date to allow for a twelve month window to
prepare for compliance.

A few other commenters felt that since there was no averaging of ACE (other than the one minute averaging within the metric) it
would allow for large deviations in ACE for prolonged periods of time. The SDT stated that the reliability standards
should not be viewed in isolation. They work together to achieve operating characteristics that are greater than
individual requirements. BAAL only addresses the duration of large ACE deviations, however, at the same time CPS1
prevents a BA from accumulating significant repetitive durations with large ACE deviations by providing a CPS1 score in
excess of 800% below passing levels for each minute that the BAAL is exceeded.

BAAL provides a guarantee that if all BAs are operating within their BAAL the interconnection frequency error will
remain less than the frequency trigger limit. The BARC SDT was unable to find a way to modify BAAL to retain the
frequency guarantee and provide additional operating margin for the small BAs.

Yes or No

associated with the version 2, which would then need to be addressed.
This project is untimely and should be postponed until there is a final
order from FERC. At that point, there may be justification to continue
with this project, expand the scope of the SAR to address any new
directives that may be included in a final order of PRC-005-2, or to
determine that a guidance document is an appropriate way to satisfy
the FERC orders.(3) The Commission specifically advised the drafting
team of PRC-005-2 to modify the standard to include reclosing relays.
Because the drafting team did not include them during that opportunity,
the drafting team should wait until a final order is issued.(4) Again, the
drafting team needs to consider other methods of answering FERC
directives. Not every directive needs to be addressed by developing or
revising a standard. Adding reclosing relays to PRC-005 only complicates
the most-violated non-CIP standard. There is enough concern about this
standard already and the drafting team should consider alternative
means to address the reclosing relay issue besides a standard
revision.(5) This project contains similar timing issues as CIP version 4
and CIP version 5 because it is being developed prior to FERC issuing a
final order on the previous version of the standard. The timing is
problematic; registered entities will be forced to constantly be focusing
on the next standard. The implementation plan should provide
additional time, similar to PRC-005-2’s two intervals, to allow registered
entities enough time to adjust their PSMT programs for Protection
Systems, and then have additional time to adjust their PSMT plan and
implement autoreclosers.(6) Thank you for the opportunity to comment.

Question 2 Comment

No

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Bonneville Power Administration

31

1. The impacts of the field trial have not been analyzed thoroughly
enough to put this to a vote at this time. In the WECC, we have seen an

Response: Thank you for your comment. Unfortunately, the comment you provided does not appear to address draft Standard
BAL-001-2.

Organization

Organization

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Yes or No

32

4. This standard seems to be moving contrary to the general trend of
standards development. While all other standards seem to be aiming for

3. BAL-001 is driven by economics, not reliability. It is easy to assess the
$$$ gains by operating to BAAL, but the additional costs incurred to your
Balancing Authority because of another Balancing Authority's operation
within the BAAL envelope is not easily calculated. Within NERC and in
general, a system operating at 60 Hz is more reliable than one operating
at some other value; however, there is no proof that the BAAL operating
range is unreliable. Studies must be run on the WECC system with offnominal frequency. This has been brought up in study team meetings,
but the studies have yet to be performed.

2. The tools for managing path flows with respect to larger allowed
deviations by participating BAs did not keep up with the RBC pilot.

increase in frequency deviations, the number of manual time error
corrections, coordinated phase shifter operations, and unscheduled flow
during the period of the field trial. It is not entirely clear to what extent
the Field Trial is responsible for these increases. The data collected has
not been made available to the individual Entities for analysis and
evaluation. At the NERC level there is some information posted but it is
not in great enough detail to be able to make a decision on the merits or
risks associated with the BAAL standard. One piece of information which
seems blatantly missing is the degree to which participating BA’s have
detuned their AGC systems for the field trial. Without this information it
seems an objective analysis of the impacts would be impossible. If we
are seeing an increase in the number of frequency excursions yet the
participating BA’s have only minimally (or not at all) detuned their AGC
algorithms then we may unknowingly be sitting on the brink of reliability
disaster should the standard pass and BA’ fully detune their AGC
systems to take full advantage of the new requirements.

Question 2 Comment

Organization

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Yes or No

33

8. There is no averaging of ACE, other than the one minute average used
in the metric. This allows large deviations in ACE for prolonged periods
of time, up to 29 minutes, without any adverse consequences to the BA
with respect to this standard.

7. Large Balancing Authorities benefit disproportionately to small
Balancing Authorities. Under certain conditions, small Balancing
Authorities may experience a more narrow operating bandwidth under
the proposed BAL-001-1 than under the existing BAL-001.

6. There are a variety of commercial issues being raised by entities
familiar with the field trial. The issues range from transmission system
flows and transmission rights being usurped by unscheduled flow to
issue of imbalances being allowed to go into a BA’s ACE and Inadvertent
Interchange balances.

5. Any field trial results in addition to the limitations pointed out in 2.
Above, are further tainted by the fact that not all BA’s are participating
in the field trial. Only about 2/3rds of the total frequency bias of the
Eastern Interconnection is represented by BA’s in the field trial. In the
WECC that percentage is higher but it is known that not all of the
“participating” BA’s have changed their control algorithms and for the
BA’s that have; the magnitude of the control system changes are not
known.

improvements to reliable system operations this standard is going the
other direction by considerably relaxing the Control Performance
Standards. It is difficult to understand how a standard which allows a BA
to accumulate extremely large negative ACE - potentially in the minutes
just prior to a major MSSC event - could possibly be an improvement for
reliability. From the control required of CPS2, this appears to be a
lowering of the bar.

Question 2 Comment

Yes or No

11. BPA believes that the proposed standard reduces the control
performance measures by allowing "looser" control and is therefore,
less stringent than the current standard, It is hard to understand how a
loosening of the control performance standards can provide an increase
in reliability.

10. BPA believes that the analysis done during the field trials have been
conducted with incomplete information, most notably they are lacking
information on exactly what changes, if any, participating BA's have
made to their control systems.

9. At this point in time BPA sees no simple solution to these issues. More
information needs to be collected from Balancing Authorities taking part
in the field trial and that information needs to be made more available
to all interested parties. More extensive analysis needs to be done
before any informed decisions can be made on this dramatic change to
the control performance standards.

Question 2 Comment

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

34

1. The Standard Drafting Team appreciates you concern with respect to uncertainty associated with the Field Trial Results.
However, the BAAL has been under Field Trial since July 2005 on the Eastern Interconnection, January 2010 in ERCOT, March
2010 on the Western Interconnection, and January 2011 in Quebec. Voluntary field trials are only as good as the willingness
of the participants. NERC cannot force BAs to participate. The Standard Drafting Team feels that a Field Trial with a duration
approaching eight years should be sufficient to evaluate a standard. Concerning the Field Trial on the Western
Interconnection, the WECC has chosen to take local responsibility for its evaluation and consequently only shared limited
data with NERC. The reports supplied by the WECC have indicated that there are still unknowns associated with the
standard, but they have failed to indicate any significant reliability impacts that can be attributed to the BAAL.
2. Managing the tools to control path flows on an interconnection is beyond the scope of the BARC SDT. However, the team
did provide a new method for estimating path flows as part of the body of work that was considered during the
development of BAAL but was not adopted by the WECC.
3. All reliability standards have some economic component. The goal is to balance the economic cost with the reliability cost to

Response: Thank you for your comments.

Organization

Yes or No

Question 2 Comment

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

35

achieve the best joint reliability/economic result. Studies performed for FERC indicate that the WECC in general is spending
more for secondary frequency control and less for primary frequency control that is economically justified. The SDT believes
that BAAL provides the BA with the correct reliability factor, being Frequency, and allows for the coordination among the
BAs to move frequency in the correct direction for the reliability of the Interconnection.
4. The appropriate goal for NERC in standards development should not only be to improve reliability, it should also be to set
reliability levels such that the additional value of improved reliability is more than the additional cost of achieving that
reliability improvement. Taking any other view will result in inappropriate reliability decisions for the customers.
5. Non-participation in a voluntary field trial is not a reason for delaying the implementation of a standard. Field Trials are held
for the express purpose of determining whether there are any problems that will arise if the new standard is implemented.
The function of NERC is not to tell each BA how to operate their unique portion of the BES, but is instead to set boundaries
that define the limits of reliable operations and allow each BA to operate freely within those limits.
6. Unscheduled energy flows that do not cause reliability problems are not reliability issues. Since these issues are not
reliability problems they should not be resolved by a reliability standard. The BAAL Field Trial has provided new information
concerning the determination of the contribution of unscheduled energy to transmission reliability. However, the BARC SDT
determined that it was beyond their scope to take action to implement changes in standards or procedures to restrict the
effects of unscheduled energy flows on transmission loading.
7. The BARC SDT was unable to determine whether the difference between BAAL and CPS2 limits is due to: 1) BAAL
inappropriately discriminating against small BAs; or, 2) CPS2 inappropriately favoring small BAs. However, the BARC SDT
was able to determine that BAAL provides a guarantee that if all BAs are operating within their BAAL the interconnection
frequency error will remain less than the frequency trigger limit. The BARC SDT was unable to find a way to modify BAAL to
retain the frequency guarantee and provide additional operating margin for the small BAs.
8. The reliability standards should not be viewed in isolation. They work together to achieve operating characteristics that are
greater than individual requirements. BAAL only addresses the duration of large ACE deviations, however, at the same time
CPS1 prevents a BA from accumulating significant repetitive durations with large ACE deviations by providing a CPS1 score in
excess of 800% below passing levels for each minute that the BAAL is exceeded.
9. The SDT posts monthly the available information on the field trial to the NERC website. WECC elected not to release the
detailed data from the field trial. The BARC SDT believes eight years of study of these issues is sufficient to make an
informed decision.
10. Results based standards provide measureable limits that define reliable operations. Results based standards should not
require information about how those results are achieved. They should require only the measured results demonstrate
reliable operations. In a results based standard environment, it is inappropriate to judge how the results are achieved; only

Organization

Yes or No

Question 2 Comment

No

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

BC Hydro and Power Authority

36

3. Increased difficulties in the planning time frame for transmission use.
The basis for setting aside the Transmission Reliability Margin might
have to be revised to account for a wider range of ACE allowed by BAAL.
This may lead to a larger transmission margin being made unavailable

2. There is no requirement for BAs to maintain their true load-resource
balance, i.e. no requirement for ACE to cross zero during any
predetermined scheduling period, or for the averaged ACE over any
predetermined scheduling period to be within a reasonable limit about
zero. The “base line” of zero-ACE for a true balance can be moved to as
far away as the BAAL limit without any consequences to the BA as long
the scheduled frequency is maintained (by other BAs with ACE in the
opposite sign). Although there is more flexibility for BAs to deploy their
resources and some potential benefit gained by reduced wear and tear
cost, BAs may interpret BAAL as their rights to withhold their resource
commitment.

1. The reliability impacts of increased unscheduled flow have not been
adequately addressed. BC Hydro suggests studying in detail those
events where a BA’s ACE was within BAAL however the Reliability
Coordinator still instructed the BAs to reduce ACE within L10 to mitigate
path transmission loading issues.

BCHA applauds the significant improvement made in this proposed
standard to add the term Reporting ACE and to create the definition for
Regulation Reserve Sharing Group. However, BCHA respectfully submits
the following reasons for its Negative vote:

they are achieved and they will result in an appropriate level of reliability.
11. The SDT is focusing in on one of the measures of reliability which is frequency. Both user’s and supplier’s equipment are
designed to operate in a safe frequency range. By focusing on frequency we provide the ability to meet this reliability goal.
Please refer to responses to 3 and 4 above.

Organization

Yes or No

5. Potential for increased hidden operating costs to Transmission
entities such as increased transmission losses caused by BAs exchanging
their large imbalances without transmission rights.

4. Increased needs in real time for the RC to monitor SOL/IROL
overloading and their instruction to BAs to scale back on ACE magnitude.
This might be not practical for an Interconnection with multiple-RCs. It
may also raise an inequity issue whereby not all BAs will be asked to
refrain from operating with BAAL at the same time.

for commercial use.

Question 2 Comment

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

37

1. Managing the tools to control path flows on an interconnection is beyond the scope of the BARC SDT. However, the team
did provide a new method for estimating path flows as part of the body of work that was considered during the
development of BAAL that could be used to determine contribution to path flows. ACE is not a definitive measure of
reliability.
2. It is impossible for any BA on a multiple BA interconnection to maintain their load-resource balance (zero ACE) at all times.
Therefore, the standard sets limits with respect to how much ACE deviation can be allowed during reliable operations. Even
CPS2 does not require a long-term average of ACE that is close to zero. There is no reliability consequence associated with
average ACE deviation as calculated for CPS2. The reliability standards should not be viewed in isolation. They work
together to achieve operating characteristics that are greater than individual requirements. BAAL only addresses the
duration of large ACE deviations, however, at the same time CPS1 prevents a BA from accumulating significant repetitive
durations with large ACE deviations by providing a CPS1 score in excess of 800% below passing levels for each minute that
the BAAL is exceeded.
3. The appropriate goal for NERC in standards development should be more than to merely improve reliability; it should also
consider whether reliability levels are set such that the additional value of improved reliability is more than the additional
cost of achieving that reliability improvement. As long as the cost of different Transmission Reliability Margin is included in
the cost benefit determination of the appropriate level of reliability, the inclusion of the change in Transmission Reliability
Margin is appropriate. Taking any other view will result in inappropriate reliability decisions for the customers.
4. The WECC study indicated that ACE deviations were as likely to result in decreases in transmission path loading as to result in

Response: Thank you for your comments.

Organization

Yes or No

Question 2 Comment

No

ReliabilityFirst votes in the Negative due to the “Regulation Reserve
Sharing Group” being an applicable Entity and the fact that there is no
functional or Registered Entity defined as a “Regulation Reserve Sharing
Group”. Absent any Entities registered as a “Regulation Reserve Sharing
Group”, compliance cannot be assessed against this entity, thus making
any requirements applicable to the “Regulation Reserve Sharing Group”
unenforceable.

No

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

seattle city light

38

Seattle City Light supports the implementation of BAAL limits to replace
CPS2, but think this draft needs more work and should not be
implemented as currently written. It appears to have been rushed.
Specifically, Seattle experienced good results in the Reliability Based
Controls field trials and supports the RACE and BAAL concepts. However,
Seattle has concerns about the compliance risk introduced by the many
new definitions and new types of reserve sharing groups proposed
under this draft. In particular are the relations among Regulation
Reserve Sharing Group, Reserve Sharing Group, and Balancing Authority
ability to designate one or another of these groups as responsible entity.
For example, as currently written there may be a possibility of conflict
between the applicability of BAL-001-2 and Requirement R2 of the

The SDT will have the Regulation Reserve Sharing Group added to the compliance registry once this standard has been approved
by the industry and FERC.

Response: Thank you for your comments.

ReliabilityFirst

increases in transmission path loading. The logic presented would be justification not to allow any changes in operations
because they might result in these same problems yet changes are made in operations often. During the field trial the SDT
has not had any Eastern Interconnection RC identify any issues as you describe.
5. The SDT believes that transmission losses are almost as likely to move upward as they are to move downward. Tightening
balancing control standards to address transmission issues is an inappropriate reason to restrict control which can
significantly increase costs for everybody.

Organization

Organization

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Yes or No

39

Seattle is also concerned that BAL-001-2 R2 “...more than 30 consecutive
clock-minutes...” requirement represents too long a time, and should be
changed to a shorter time frame to better reflect the existing and
proposed sub-hour scheduling windows and other Standards limiting the
time that a Balancing Authority is not positively supporting system

Another example is that Attachment 1 used to describe how to calculate
CPS1 does not appear to be complete. It needs to be revised to include
the methodology for calculating the CPS1 for the Regulation Reserve
Sharing Group.

Further Requirement R2 of the Standard states that: R2. Each Balancing
Authority shall operate such that its clock†minute average of
ReportingACE does not exceed its clock†minute Balancing Authority
ACE Limit (BAAL) for morethan 30 consecutive clock†minutes, as
calculated in Attachment 2, for the applicableInterconnection in which
the Balancing Authority operates.[Violation Risk Factor:Medium] [Time
Horizon: Real†time Operations]Seattle finds the Standard is not clear
if requirement R.2 is applicable to the Regulation Reserve Sharing Group
as a group or to all BAs individually participating in Regulation Reserve
Sharing Group. As currently written a BA can argue that R.2 is not
applicable if they are participating in Regulation Reserve Sharing Group,
and Seattle is not sure if this was the intent of the Standard Drafting
Team.

Standard. As written Applicability Section 4.0 states the Standard is
applicable to: 4.1 Balancing Authority 4.1.2 A balancing Authority that is
a member of Regulation Reserve Sharing Group is the Responsible Entity
only in period during which the Balancing Authority is not in active
status under the applicable agreement or governing rules for the
Regulation Reserve Sharing Group.
4.2. Regulation Reserve
Sharing Group.

Question 2 Comment

Yes or No
frequency.

Question 2 Comment

No

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Nebraska Public Power District

40

The term “active status” used in section 4.1.2 is not a defined term and
may not be included in any regulation reserve sharing agreements.
There should be more clarity around this term. Given the concerns
noted above, are there minimum time periods when a regulation
reserve sharing group may not be in “active status”. For example, can a
regulation reserve sharing pool be inactive for a portion of an hour, or
conversely only be active for a portion of the hour? The standard needs
more clarification on what active status means and how frequently the
status can change.

The applicability section of the standard allows for periods of time when
a BA may be responsible for meeting the requirements of this standard
and times when a Regulation Reserve Sharing Group may be responsible
for meeting the requirements of this standard. However R1 requires
calculating a 12 month average CPS 1. Neither the requirement nor the
attachment address how a responsible entity is to handle those periods,
which may be portions of a month, day or hour when they are not
responsible for meeting the requirements. If the period is to be treated
as bad data, the standard or attachment that details the calculation
needs to specify how those periods are handled.

The SDT has not seen any issues arise during the field trial concerning the 30 clock-minute time window. In addition, the SDT
believes that this is complementary with time limits established in transmission related standards. The SDT received no other
comments concerning the 30 clock-minute duration for BAAL and believes that it is appropriate.

Each requirement in a standard is not necessarily applicable to all entities listed in the applicability section. Requirement R2 in
the proposed standard is only applicable to the BA. The SDT does not believe that a RRSG can satisfy the requirements of BAAL.

Response: Thank you for your comments.

Organization

Yes or No

Question 2 Comment

No

The City of Tallahassee (TAL) believes that six months is insufficient time
to modify the software, make the changes, and monitor performance in
today’s CIP world. Cyber standards have progressed significantly since
the Standards Drafting Team analyzed the potential timeframes for
implementation. TAL contends that 12 months would be more
appropriate.

No

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Western Area Power Administration

41

One piece of information which seems blatantly missing is the degree to
which participating BA’s have detuned their AGC systems for the field
trial. Without this information it seems an objective analysis of the
impacts would be impossible. If we are seeing an increase in the number

The impacts of the field trial have not been analyzed thoroughly enough
to put this to a vote at this time. In the WECC, we have seen an increase
in frequency deviations, the number of manual time error corrections,
coordinated phase shifter operations, and unscheduled flow during the
period of the field trial. It is not entirely clear to what extent the Field
Trial is responsible for these increases. The data collected has not been
made available to the individual Entities for analysis and evaluation. At
the NERC level there is some information posted but it is not in great
enough detail to be able to make a decision on the merits or risks
associated with the BAAL standard.

The SDT agrees with your comment and has modified the standard to provide for 12 months after FERC approval.

Response: Thank you for your comments.

City of Tallahassee

The SDT included the possibility of active versus inactive status for the potential of events such as, but not limited to telemetry
failure.

The calculation of CPS1 would be the same whether or not a BA participates in a RRSG.

Response: Thank you for your comments.

Organization

Yes or No

Under certain conditions, small Balancing Authorities may experience a
more narrow operating bandwidth under the proposed BAL-001-1 than
under the existing BAL-001.

Western recommends that the BARC SDT consider establishing an ACE
Transmission Limit for the Western Interconnection. The impacts are
not the same for Large Balancing Authorities as they are for small
Balancing Authorities.

This standard seems to be moving contrary to the general trend of
standards development. While all other standards seem to be aiming
for improvements to reliable system operations this standard is going
the other direction by considerably relaxing the Control Performance
Standards. It is difficult to understand how a standard which allows a BA
to accumulate extremely large negative ACE - potentially in the minutes
just prior to a major MSSC event - could possibly be an improvement for
reliability. From the control required of CPS2, this appears to be a
lowering of the bar. The WECC experienced fewer instances where SOL
were exceeded, when there was a ACE Transmission Limit of 4 times L
sub 10 during the RBC Field Trial.

of frequency excursions yet the participating BA’s have only minimally
(or not at all) detuned their AGC algorithms then we may unknowingly
be sitting on the brink of reliability disaster should the standard pass and
BA’ fully detune their AGC systems to take full advantage of the new
requirements.

Question 2 Comment

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

42

1. The Standard Drafting Team appreciates you concern with respect to uncertainty associated with the Field Trial Results.
However, the BAAL has been under Field Trial since July 2005 on the Eastern Interconnection, January 2010 in ERCOT, March
2010 on the Western Interconnection, and January 2011 in Quebec. Voluntary field trials are only as good as the willingness
of the participants. NERC cannot force BAs to participate. The Standard Drafting Team feels that a Field Trial with a duration

Response: Thank you for your comments.

Organization

No

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Response: Thank you for your comments.

NYISO

5.

4.

3.

2.

Yes or No

Question 2 Comment

43

The NYISO has concerns based on results of the field trials that were
conducted. These field trials have indicated the potential for an
increased number of SOL violations as well as potential for increased
ACE due to large inadvertent flows with the proposed BAAL limits based
on frequency triggers. It is not appropriate to indicate the SOL/IROL
Standards will address these additional overloads as the flows that are
causing the overloads due to the increase ACE are not identifiable in any
contingency management system. We would propose dropping the
BAAL calculation until a wider field trial could be conducted.

approaching eight years should be sufficient to evaluate a standard. Concerning the Field Trial on the Western
Interconnection, the WECC has chosen to take local responsibility for its evaluation and consequently only shared limited
data with NERC. The reports supplied by the WECC have indicated that there are still unknowns associated with the
standard, but they have failed to indicate any significant reliability impacts that can be attributed to the BAAL.
Results based standards provide measureable limits that define reliable operations. Results based standards should not
require information about how those results are achieved. They should require only the measured results demonstrate
reliable operations. In a results based standard environment, it is inappropriate to judge how the results are achieved; only
they are achieved and they will result in an appropriate level of reliability.
The appropriate goal for NERC in standards development should not only be to improve reliability, it should also be to set
reliability levels such that the additional value of improved reliability is more than the additional cost of achieving that
reliability improvement. Taking any other view will result in inappropriate reliability decisions for the customers.
The Eastern Interconnection has not experienced increases in SOL exceedances that were attributed to the Field Trial;
therefore, any fixed ACE Transmission Limit would be inappropriate to add to a continent wide standard.
The BARC SDT was unable to determine whether the difference between BAAL and CPS2 limits is due to: 1) BAAL
inappropriately discriminating against small BAs; or, 2) CPS2 inappropriately favoring small BAs. However, the BARC SDT
was able to determine that BAAL provides a guarantee that if all BAs are operating within their BAAL the interconnection
frequency error will remain less than the frequency trigger limit. The BARC SDT was unable to find a way to modify BAAL to
retain the frequency guarantee and provide additional operating margin for the small BAs.

Organization

Yes or No

Question 2 Comment

No

The question above is not a Yes/No question. The City of Tallahassee
(TAL) believes that six months is insufficient time to modify the
software, make the changes, and monitor performance in today’s CIP
world. Cyber standards have progressed significantly since the
Standards Drafting Team analyzed the potential timeframes for
implementation. TAL contends that 12 months would be more
appropriate.

Avista

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

No

44

The RBC Field Trial in the WECC provided enough information to
determine if RBC had any effects on reliability. The WECC PWG’s July
2012 report to the WECC OC clearly documented frequency error was
increasing over previous operation under CPS2. It documented
increasing frequency in the negative direction in heavy load hours
(particularly morning and evening peaks) and increasing frequency error

Response: Thank you for your comments. The SDT agrees with your comment and has modified the standard to provide for 12
months after FERC approval.

City of Tallahassee

The SDT believes that the implementation of BAAL as an enforceable standard would result in similar system performance as it
relates to transmission flows as presently achieved with CPS 2.

It is the opinion of the SDT that conducting a wider field trial beyond what was conducted in the West, which involved 70% of
the BAs, would not provide any additional benefit. Sufficient data exists to support that reliability is not degraded.

The SDT has focused on frequency as the measure of reliability for this standard. Both user’s and supplier’s equipment are
designed to operate in a safe frequency range. By focusing on frequency we provide the ability to meet this reliability goal.

The appropriate goal for NERC in standards development should not only be to improve reliability, it should also be to set
reliability levels such that the additional value of improved reliability is more than the additional cost of achieving that
reliability improvement. Taking any other view will result in inappropriate reliability decisions for the customers.

The SDT believes that BAAL provides the BA with the correct reliability factor and allows for the coordination among the BAs to
move frequency in the correct direction for the reliability of the Interconnection.

Organization

Organization

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Yes or No

45

Finally, loose ACE control effectively eliminates the effectiveness of the
WECC Automatic Time Error Correction system. WECC ATEC depends on

The RBC formula advantages larger Balancing Authorities by allowing
looser control and wider frequency ranges. Whereas a smaller BA may
see the BAAL limits quickly shrink at deviations near 0.050 Hz, a larger
BA can still run a large ACE, creating inadvertent flow and secondary
control problems for smaller BA’s.

Additional control problems are created when frequency deviations
beyond 0.030 Hz occur, exceeding governor deadband on generating
units (IEEE standard deadband). If these units are being used for
Automatic Generation Control (AGC), they will move to governor
control, generally disabling the AGC functionality. This does not add to
system reliability, and likely detracts from it.

Increasing inadvertent accumulations are also documented in the PWG
report. Increasing inadvertent, unscheduled flow events and
curtailments, and prolonged frequency deviations beyond 0.030 Hz are
not hallmarks of a reliable system. No studies, or actual events, have
demonstrated that the WECC system can perform for a 2800 MW (G-2)
generation loss with an initial frequency of 59.94 Hz or lower.

Manual time error corrections and hours of manual time error
corrections are approximately double what they had been. The PWG
report documents increasing unscheduled flow events with the ACE
Transmission Limit (ATL) being increased or eliminated. This has
continued on into 2013. This indicates that RBC has a negative effect on
path flow control and management.

in the positive direction during light load hours. This report also shows
Epsilon 1 and Epsilon 10 increasing significantly over past CPS2
performance years.

Question 2 Comment

Organization

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Yes or No

46

The summary statement on page 6 is not supported by the field trials.
The summary statement says that RBC improves upon CPS2 by

Comments: “BAL-001-1 Real Power Balancing Control Standard
Background Document” Page 4 has an illuminating statement.”CPS2 is:
Designed to limit a Control Area’s (now BA) unscheduled power flow.”
This is a significant issue in the WECC. Unscheduled power flow
becomes unmanageable without the CPS2 requirement. There is no
other way to control BA to BA power flow if a BA is not required to
maintain its Net Actual Interchange within a limit.

With respect to R2/M2, how many times can a BA exceed BAAL limits for
30 minutes? Can a BA exceed BAAL for 27 minutes every hour? A limit
based on so many minutes exceeding BAAL per month or some similar
measure may be more likely to incent the desired control performance.
How do you measure severity if an event happens many times, but
never exceeds 30 minutes? Is 29 minutes ok and 31 minutes a risk to
the interconnection?

R2 is not a frequency control requirement under all conditions, it is a
requirement that is used under normal conditions. It is designed to
operate around small frequency deviations. For large frequency
deviations, frequency support is required and measured by ACE recovery
under BAL-002 (DCS).

CPS2 compliance in order to ensure that a BA is continuously paying
back its accumulated Primary Inadvertent balance. With the loose limits
of RBC, the Primary Inadvertent payback term is small enough that it
may not even influence the BA’s AGC control algorithm. This can be
clearly seen by the increasing WECC frequency deviation beginning with
the field trial in 2010. ATEC was implemented in WECC in 2003, and low
frequency deviation from 2003-2009 is easily seen the PWG 2012 WECC
OC report.

Question 2 Comment

Yes or No

The inability to control path flows effectively, requiring unscheduled
flow mitigation to remain within System Operating Limits, inherently
decreases reliable operation. CPS2 takes frequency into account with
the frequency component of the ACE equation. To claim that operating
to the ACE equation does not inherently support system frequency is not
logical. The CPS2 requirement should be retained, and the BAAL should
not be adopted.

dynamically altering ACE limits based on frequency. The WECC field trial
conclusively demonstrates that frequency control is worse and
frequency error is greater, indicating RBC decreases reliability compared
to CPS2.

Question 2 Comment

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

47

1. The Standard Drafting Team appreciates you concern with respect to uncertainty associated with the Field Trial Results.
However, the BAAL has been under Field Trial since July 2005 on the Eastern Interconnection, January 2010 in ERCOT, March
2010 on the Western Interconnection, and January 2011 in Quebec. Voluntary field trials are only as good as the willingness
of the participants. NERC cannot force BAs to participate. The Standard Drafting Team feels that a Field Trial with a duration
approaching eight years should be sufficient to evaluate a standard. Concerning the Field Trial on the Western
Interconnection, the WECC has chosen to take local responsibility for its evaluation and consequently only shared limited
data with NERC. The reports supplied by the WECC have indicated that there are still unknowns associated with the
standard, but they have failed to indicate any significant reliability impacts that can be attributed to the BAAL.
2. The WECC Unscheduled Flow Administrative Subcommittee (UFAS) evaluation of 2012 events showed the BAAL to be a
relatively minor issue in regards to the events seen. The PWG evaluation was less in depth than the UFAS evaluation.
3. As the Interconnection approaches lower frequencies such as 59.94 Hz, BAAL will provide the BA direction to return their
ACE closer to zero; whereas CPS2 does not provide the same guidance.
4. While ASME had a 36 mHz standard (PTC 20.1-1977 Speed and Load Governing Systems for Steam Generating Units) until
2003, it is no longer a part of any recognized standard of IEEE, ASME or NERC to the knowledge of this SDT. All frequency
control results in normal distributions of frequency error. This has been demonstrated on all of the North American
Interconnections. Looser ACE control will not eliminate the effectiveness of the WECC ATEC system because the frequency
error will still be normally distributed around scheduled frequency. The effectiveness of the inadvertent payback will also

Response: Thank you for your comments.

Organization

Yes or No

Question 2 Comment

No

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

City of Tallahassee

48

This is not a yes/no question. The City of Tallahassee (TAL) believes that
six months is insufficient time to modify the software, make the
changes, and monitor performance in today’s CIP world. Cyber
standards have progressed significantly since the Standards Drafting

continue. AGC should continue to function normally even when units are outside of the deadband.
5. The BARC SDT was unable to determine whether the difference between BAAL and CPS2 limits is due to: 1) BAAL
inappropriately discriminating against small BAs; or, 2) CPS2 inappropriately favoring small BAs. However, the BARC SDT
was able to determine that BAAL provides a guarantee that if all BAs are operating within their BAAL the interconnection
frequency error will remain less than the frequency trigger limit. The BARC SDT was unable to find a way to modify BAAL to
retain the frequency guarantee and provide additional operating margin for the small BAs.
6. All frequency control results in normal distributions of frequency error. This has been demonstrated on all of the North
American Interconnections. Looser ACE control will not eliminate the effectiveness of the WECC ATEC system because the
frequency error will still be normally distributed around scheduled frequency. The effectiveness of the inadvertent payback
will also continue.
7. The BAAL is applicable every minute of every day. Exceeding the BAAL for more than 30 clock-minutes will be a violation
regardless of frequency level.
8. The reliability standards should not be viewed in isolation. They work together to achieve operating characteristics that are
greater the individual requirements. BAAL only addresses the duration of large ACE deviations, however, at the same time
CPS1 prevents a BA from accumulating significant repetitive durations with large ACE deviations by providing a CPS1 score in
excess of 800% below passing levels for each minute that the BAAL is exceeded.
9. Unscheduled energy flows that do not cause reliability problems are not reliability issues. Since these issues are not
reliability problems they should not be resolved by a reliability standard. The BAAL Field Trial has provided new information
concerning the determination of the contribution of unscheduled energy to transmission reliability. However, the BARC SDT
determined that it was beyond their scope to take action to implement changes in standards or procedures to restrict the
effects of unscheduled energy flows on transmission loading.
10. The SDT has focused on frequency as the measure of reliability for this standard. Both user’s and supplier’s equipment are
designed to operate in a safe frequency range. By focusing on frequency we provide the ability to meet this reliability goal.
11. It is correct that CPS2 is affected by frequency through the ACE equation, but the commenter failed to realize that the 10
minute average required in the CPS2 measure can be detrimental to frequency because an average can incent behavior that
causes control actions that make frequency worse instead of better.

Organization

Yes or No
Team analyzed the potential timeframes for implementation. TAL
contends that 12 months would be more appropriate.

Question 2 Comment

No

We do not see the need to create the two new terms (RRSG and RRSG
Reporting ACE) and the applicability exceptions for BAs that receives
overlap regulation service or participate in the RRSG. The Standard
should stipulate the requirements for each BA to meet the CPS1 and
BAAL requirements only, regardless of how it arranges for the regulation
services to meet these requirements. We suggest removing the two
new terms, and the applicability exception for BAs receiving overlap
regulation service or participating in the RRSG. The currently posted
version appears to place requirements on both individual BAs and the
RRSG, but the obligations for the latter are not clearly stipulated in the
Standard. There is a need to have the RRSG requirements stipulated for
the RRSG so long as the Standard places the obligation to each BA to
meet the CPS1 and BAAL requirements.

No

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

ISO New England Inc.

49

We do not see the need to create the two new terms (RRSG and RRSG

The SDT has added clarifying language to Attachment 2 on how bad data is handled for BAAL.

The SDT is not mandating that a BA has to participate in a RRSG but could if it was determined to be in their best interest. The
SDT is simply providing an additional tool for BAs to use and did not want to rule out any tool that could be used to satisfy
compliance within a standard.

The calculation of CPS1 would be the same whether or not a BA participates in a RRSG.

The SDT has eliminated the term RRSG Reporting ACE.

Response: Thank you for your comments.

Northeast Power Coordinating
Council

Response: Thank you for your comments. The SDT agrees with your comment and has modified the standard to provide for 12
months after FERC approval.

Organization

Yes or No

Reporting ACE) and the applicability exceptions for BAs that receives
overlap regulation service or participate in the RRSG. The Standard
should stipulate the requirements for each BA to meet the CPS1 and
BAAL requirements only, regardless of how it arranges for the regulation
services to meet these requirements. We suggest removing the two new
terms, and the applicability exception for BAs receiving overlap
regulation service or participating in the RRSG.The currently posted
version appears to place requirements on both individual BAs and the
RRSG, but the obligations for the latter are not clearly stipulated in the
Standard. There is a need to have the RRSG requirements stipulated for
the RRSG so long as the Standard places the obligation to each BA to
meet the CPS1 and BAAL requirements.

Question 2 Comment

No

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Oklahoma Gas & Electric

50

While we appreciate the attempt to streamline and simplify the
standard, the requirement of Balancing Authorities providing Overlap
Regulation Service should be moved back into the requirements section.
The Standard should be enforceable based solely on the
Requirements.”The most critical element of a Reliability Standard is the
Requirements. As NERC explains, “the Requirements within a standard
define what an entity must do to be compliant . . . [and] binds an entity
to certain obligations of performance under section 215 of the FPA.” If

The SDT has added clarifying language to Attachment 2 on how bad data is handled for BAAL.

The SDT is not mandating that a BA has to participate in a RRSG but could if it was determined to be in their best interest. The
SDT is simply providing an additional tool for BAs to use and did not want to rule out any tool that could be used to satisfy
compliance within a standard.

The calculation of CPS1 would be the same whether or not a BA participates in a RRSG.

The SDT has eliminated the term RRSG Reporting ACE.

Response: Thank you for your comments.

Organization

Yes or No

properly drafted, a Reliability Standard may be enforced in the absence
of specified Measures or Levels of Non-Compliance.” (NOPR and Order
693)

Question 2 Comment

No

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Independent Electricity System
Operator

51

While we do not see the need to create the two new terms (RRSG and
TTSG Reporting ACE), if the terms were to be included, the term RRSG
should be vetted through the functional model working group PRIOR to
including it in this standard as it appears to be a new functional entity.
As such, it’s roles should be defined in the functional model prior to
being incorporated into any NERC standards.We do not see the need to
create the two new terms (RRSG and RRSG Reporting ACE) and the
applicability exceptions for BAs that receives overlap regulation service
or participate in the RRSG. The standard should stipulate the
requirements for each BA to meet the CPS1 and BAAL requirements
only, regardless of how it arranges for the regulation services to meet
these requirements. We suggest removing the two new terms, and the
applicability exception for BAs receiving overlap regulation service or
participating in the RRSG.We generally supported the previous draft that
stipulates the requirements for each BA. We are unable to support the
currently posted version as it appears to place requirements on both
individual BAs and the RRSG but the obligations for the latter is not
clearly stipulated in the standard. At any rate, we do we see a need to
have that latter (RRSG) requirements stipulated for the RRSG so long as
the standard places obligation to each BA to meet the CPS1 and BAAL
requirements.

Based on conversations with NERC staff, the SDT moved the requirement concerning Overlap Regulation Service to the
applicability section. The SDT, as well as NERC staff, did not believe that this should be a requirement.

Response: Thank you for your comments.

Organization

Yes or No

Question 2 Comment

No

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

SPP Standards Review Group

52

As written, R2 applies only to a Balancing Authority. It should be
reworded to apply to both a Balancing Authority or Regulation Reserve
Sharing Group as is R1. Substitute Responsible Entity for Balancing

As written R1 requires any applicable BA to maintain CPS1 for the
Interconnection within which it operates at 100 percent or higher. The
rolling 12-month calculation needs additional clarification also. We
suggest the requirement should be rewritten to read:The Responsible
Entity shall operate such that its Control Performance Standard 1 (CPS1),
calculated based on the applicable Interconnection in which it operates
in accordance with Attachment 1, is greater than or equal to 100
percent for each consecutive 12-month period. Each consecutive 12month period shall be evaluated monthly.

With the introduction of the Regulating Reserve Sharing Group there
appears to be a registration gap. There currently isn’t a Regulating
Reserve Sharing Group entity in the Functional Model. It would appear
that such a registration would have to be made in order to be able to
hold the Regulation Reserve Sharing Group accountable for compliance
purposes. Providing this is done, then R1 and R2 should reflect the
applicability to both the Balancing Authority and the Regulation Reserve
Sharing Group.

The SDT has added clarifying language to Attachment 2 on how bad data is handled for BAAL.

The SDT is not mandating that a BA has to participate in a RRSG but could if it was determined to be in their best interest. The
SDT is simply providing an additional tool for BAs to use and did not want to rule out any tool that could be used to satisfy
compliance within a standard.

The calculation of CPS1 would be the same whether or not a BA participates in a RRSG.

The SDT has eliminated the term RRSG Reporting ACE.

Response: Thank you for your comments.

Organization

Yes or No

In the last line of Attachment 2, insert ‘Overlap’ in front of ‘Regulation
Service’.

Likewise we would suggest deleting the comma following ‘Attachment 2’
in R2. This links the ending phrase of the sentence to the calculation,
where it should be, more tightly.

Authority in the requirement.

Question 2 Comment

Yes

Manitoba Hydro

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

No

Keen Resources Ltd.

The SDT has added the word “Overlap” as you suggested.

53

(3) Data Retention - capitalize three instances of ‘compliance
enforcement authority’ in this section.

(2) Applicability 4.1.2 - add an ‘s’ on the end of the word ‘period’. In
addition, add the word ‘the’ before ‘governing rules’.

(1) (Proposed) Effective Date in both the Standard and Implementation
Plan - remove the “ ‘ “ following the word ‘Trustees’ because it is not
defined this way in the Glossary of Terms.

Although Manitoba Hydro is in support of the standard, we have the
following clarifying suggestions:

The SDT believes that the current writing of Requirement R2 is correct and provides the necessary clarity.

Each requirement in a standard is not necessarily applicable to all entities listed in the applicability section. Requirement R2 in
the proposed standard is only applicable to the BA. The SDT does not believe that a RRSG can satisfy the requirements of BAAL.

The SDT has added clarifying language to Requirement R1 to address your concern.

The Regulation Reserve3 Sharing Group will be added to the Compliance Registry prior to the standard going into effect.

Response: Thank you for your comments.

Organization

Yes or No

(10) General - there is inconsistency throughout the standard and
Attachments with respect to the following words: ‘12 month period’,
‘rolling 12 month basis’, ‘12-calendar months’, ‘12-month’. We suggest
selecting one of these terms and using it throughout the standard and
attachments.

(9) VSL, R2 and Attachment 1, CPS1 - add a ‘-’ between the words ‘clock
minutes’ for consistency with the standard. In addition, the words ‘for
the applicable Interconnection’ should be added for consistency with
the language of R2 and the VSL for R1.

(8) M1, M2 - the term ‘Energy Management System’ is not found in the
Glossary and should be defined.

(7) R2 - add the words ‘accordance with’ before ‘Attachment 2’.

(6) R2/M2 - please clarify if this requirement/measure should refer only
to Balancing Authority as opposed to Responsible Entity?

(5) R1 - for clarity, ‘it’ should be specified as the ‘Responsible Entity’.

(4) R1 - the words ‘12 month period’ should be changed to ‘rolling 12
month basis’ for consistency with the VSL table.

Question 2 Comment

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

54

The SDT has made the modification as requested.
The SDT has made the modification as requested.
The SDT has made the modification as requested.
The SDT has added clarifying language to the requirement.
The SDT believes that the use of the word “it” provides the necessary clarity.
Each requirement in a standard is not necessarily applicable to all entities listed in the applicability section. Requirement
R2 in the proposed standard is only applicable to the BA. The SDT does not believe that a RRSG can satisfy the
requirements of BAAL.
7) The SDT has made the modification as requested.

1)
2)
3)
4)
5)
6)

Response: Thank you for your comments.

Organization

Yes or No

Yes

Assuming we are wrong and that the drafting team has authority under
their SAR or a specific FERC directive to modify the definitions in BAL001, we have the following comments. With regard to the ACE equation
and the WECC ATEC term, we recommend that the ACE equation be
simplified and made such that it would work with any interconnection.
We recommend the term IATEC be changed to ITC, which would stand
for Time Control. The balancing standards should limit the magnitude of
TC to a value such as 20% of Bias. This would work for both the WECC
and HQ approach to controlling time error and assisting in inadvertent
interchange management (WECC). It would also give the Eastern
Interconnection a tool to reduce the number of Time Error Corrections,
which will be important if we want to encourage generators to reduce
their deadbands under BAL-003-1.

Question 2 Comment

Yes

Yes

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Salt River Project

Response: Thank you for your comments.

Duke Energy

55

There is reasonable concern that the large ACE values that the standard
permits under certain conditions will cause excessive unscheduled flow
on qualified transmission paths. We believe that this issue can be

Duke Energy has long supported the Field Trial of the Balancing
Authority ACE Limit (BAAL) and supports its adoption in place of the
current CPS2 as proposed in BAL-001-2.

The SDT has chosen not to include a generic time error correction term in the Reporting ACE equation definition. The SDT has
modified the definition to address concerns raised by the industry.

Response: Thank you for your comments.

MISO Standards Collaborators

8) The SDT has removed the term “Energy Management System”.
9) The SDT has made the modification as requested.
10) The SDT has corrected the inconsistency that you have described.

Organization

Yes
Yes

Tucson Electric Power Co

Energy Mark, Inc.

Yes or No

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Texas Reliability Entity

Yes

EnerVision, Inc.

Response: Thank you for your comments.

Organization

56

3) For Requirement R2, does there need to be an exclusion for the 30
consecutive clock-minute average if the BA experiences an EEA event or
has a Balancing Contingency event within the 30 minute period? It
seems feasible that if a BA experiences an EEA with extended low
frequency or a Balancing Contingency event with an extended recovery
period, that the clock-minute average for R2 might subsequently fail. Is
this the intent of the SDT?

2) Attachment 2 also needs additional clarification regarding
valid/invalid data. If a one-minute frequency sample is determined to
not be valid, how is the 30 consecutive clock-minute count affected?
Does the invalid minute count as an exceedance, or does the count
ignore the invalid minute, or does the count start over at 0?

1) The Implementation Plan does not include the WECC ATEC term. The
ACE equation should be simplified so that it can apply to any
interconnection. Any Time Error Correction term or alternate tertiary
control term added to the ACE equation should enable any
interconnection to control time error and reduce inadvertent
interchange.

managed by the Reliability Coordinator through enforcement of existing
standards, but may require changes to current practices.

Question 2 Comment

Yes or No

Question 2 Comment

AEP has suggested modifications regarding scope and content in our
responses to Q1 & Q3. Most concerning to us are the topics raised in our
response to Q3 (below).

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

MRO NERC Standards Review Forum

57

2) With regard to the ACE equation and the WECC ATEC term, we
recommend that the ACE equation be simplified and made such that it
would work with any interconnection. We recommend the term IATEC
be changed to ITC, which would stand for Tertiary Control.
(Alternatively, clarify that IATEC is equal to ITC. This way the reporting
and operating number would be the same.) The balancing standards
should limit the magnitude of TC to a value such as 20% of Bias. This
would work for both the WECC and HQ approach to controlling time
error and assisting in inadvertent interchange management (WECC). It
would also give the Eastern Interconnection a tool to reduce the number
of Time Error Corrections, which will be important if we want to
encourage generators to reduce their dead-bands under BAL-003-1.

1) Unless there is justification we missed, the new definitions should be
removed.

Assuming we are wrong and that the drafting team has authority under
their SAR to modify BAL-001, we have the following comments.

Response: Thank you for your comment. Please refer to our responses above.

American Electric Power

1) The SDT has chosen not to include a generic time error correction term in the Reporting ACE equation definition. The SDT
has modified the definition to address concerns raised by the industry.
2) The SDT has added clarifying language to Attachment 2 on how bad data is handled for BAAL.
3) The SDT discussed this issue in great detail. The SDT decided that it would not be in the best interest of reliability to grant
any exceptions.

Response: Thank you for your comments.

Organization

Yes or No

Question 2 Comment

ERCOT ISO suggests that the drafting team consider adding the following
language to the beginning of Requirement R2: The BAAL measure in R2
is a single event performance measurement similar to BAL-002-2 R1.
BAL-002-2 R1 does not apply when a BA is in Emergency Alert Level 2 or
3. During EEA 2 or 3, priority should be given to returning the system to
a secure state. Arguably this should exclusion should apply to all
emergency conditions (EEA 1, EEA 2, and EEA 3). Consistent with the
exclusion in BAL-002-2 R1, ERCOT suggests that the SDT consider adding
the language below to BAL-001-2 R2:"'Except when an Energy
Emergency Alert Level 2 or Level 3 is in effect' each Balancing Authorty
shall operate such that its clock-minute average of Reporting ACE does
not exceed its clock-minute Balancing Authority ACE Limit (BAAL) for
more than 30 consecutive clock-minutes, as calculated in Attachment 2,
for the applicable Interconnection in which the Balancing Authority
operates. [Violation Risk Factor: Medium] [Time Horizon: Real-time
Operations]"ERCOT ISO is voting "no" for the preceding reasons.
However, if ERCOT ISO's proposed revisions are adopted, ERCOT ISO
would support the standard.

58

Need a technical justification for the various Epsilon values specified.

Modesto Irrigation District

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

N/A

PPL NERC Registered Affiliates

Response: Thank you for your comments. The SDT discussed this issue in great detail. The SDT decided that it would not be in
the best interest of reliability to grant any exceptions.

ERCOT

2 – The SDT has modified the definition for Reporting ACE based on the collective comments from the industry.

1 – The SDT believes that the new definitions are needed to provide necessary clarity for the standard.

Response: Thank you for your comments.

Organization

Yes or No

Question 2 Comment

PJM is, in general, supportive of this standard with the exception noted
in comments for question 1.

PacifiCorp supports this draft.

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Powerex Corp.

59

Powerex believes that the proposed draft standard is deficient in many
respects as highlighted by commenters in the previous posting period.
Specifically Powerex notes the following concerns in the proposed
standard that highlight the inadequacy of the proposed requirements to
uphold the reliability of interconnections. If these concerns are not
adequately addressed the resultant standard could lead to degradation
in reliability.The deficiencies include:1) The proposed standard allows
for an entity to be outside of its BAAL limit for 29 minutes and be inside
the limit for one minute, which provides a framework that allows an
entity to possibly operate outside of the prescribed bounds 95 % of the
time. The consequences of allowing such operations has not been
adequately addressed by the drafting team, and allowing this standard
to move forward with such latitude could lead to reliability issues. 2)
The proposed standard does not restrict or limit BAs during periods of
high congestion, when unscheduled flow on the entire system is causing
reliability issues and/or exceedance of limits. Under the proposed
standard the transmission path operators and BAs are forced to deal
with unscheduled flows on the system without adequate tools or
procedures in place to remedy the reliability events. During the field

Response: Thank you for your comments. Please refer to our response to Question 1.

PJM Interconnection, L.L.C

Response: Thank you for your comments.

PacifiCorp

Response: Thank you for your comment. The Epsilon values were developed during the implementation of CPS1. These values
are reviewed under the auspices of the NERC OC annually.

Organization

Yes or No

trial of the proposed standard these issues have been experienced in the
WECC, where congestion management of non-Qualified and Qualified
paths has created various operating issues for the entities and Reliability
Coordinators. The consequences of allowing unlimited use of a
transmission system via unlimited unscheduled flows, without better
mechanisms to control flows, could lead to reliability events. The
proposed standard does not provide the authority to the Reliability
Coordinators to control and/or propose new operating procedures (eg.
Limiting all BAs in the interconnection to operate within L10 during
period of congestion) that mitigate unscheduled flows that are adversely
impacting the transmission grid. This needs to be addressed in this
proposed standard so that during high congestion periods, regardless of
system frequency, BAs bring ACE limits within L10 or some other
suitable limitation that decreases the adverse impact.3) The proposed
standard puts no limits on ACE during times of normal frequency, which
allows BAs to inappropriately “lean” on other generation, or to push
excessive amount of energy on to the transmission system. This
deficiency allows a BA to obtain energy or push unscheduled energy
across the interties during times that can be economically advantageous
to the BA without regard to impacts upon neighboring BAs, load serving
entities and transmission customers. It is paramount that the current
standard, with CPS2, remain in place until such time that the reliability
issues associated with the draft standard are resolved.

Question 2 Comment

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

60

1. The reliability standards should not be viewed in isolation. They work together to achieve operating characteristics that are
greater than individual requirements. BAAL only addresses the duration of large ACE deviations, however, at the same time
CPS1 prevents a BA from accumulating significant repetitive durations with large ACE deviations by providing a CPS1 score in
excess of 800% below passing levels for each minute that the BAAL is exceeded.
2. The Standard Drafting Team appreciates your concern with respect to uncertainty associated with the Field Trial Results.

Response: Thank you for your comments.

Organization

Yes or No

Question 2 Comment

See comment in response #1.

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Tacoma Power

61

Tacoma Power does not support the proposed standard. BAL-001 as
proposed moves forward with a control standard that has not yet been
fully vetted. Since the RBC field trial began in 2010, with a significant
portion of WECC BA participation, results point to noteworthy reliability
and market related issues. As the RBC allows larger BAs looser control
(i.e. larger ACE values) and wider frequency values, the results include:
increased coordinated phase shifter operations, dramatic increase in
schedule curtailments due to unscheduled flow, frequency increasing in
a negative direction during heavy load hours and positive direction
during light load hours, increased manual time error corrections and
hours of manual time error corrections and increasing inadvertent

Response: Thank you for your comment. Please refer to our response to Question #1.

SMUD

However, the BAAL has been under Field Trial since July 2005 on the Eastern Interconnection, January 2010 in ERCOT, March
2010 on the Western Interconnection, and January 2011 in Quebec. Voluntary field trials are only as good as the willingness
of the participants. NERC cannot force BAs to participate. The Standard Drafting Team feels that a Field Trial with a duration
approaching eight years should be sufficient to evaluate a standard. Concerning the Field Trial on the Western
Interconnection, the WECC has chosen to take local responsibility for its evaluation and consequently only shared limited
data with NERC. The reports supplied by the WECC have indicated that there are still unknowns associated with the
standard, but they have failed to indicate any significant reliability impacts that can be attributed to the BAAL.
3. Managing the tools to control path flows on an interconnection is beyond the scope of the BARC SDT. However, the team
did provide a new method for estimating path flows as part of the body of work that was considered during the
development of BAAL but was not adopted by the WECC.
4. Unscheduled energy flows that do not cause reliability problems are not reliability issues. These issues should not be
resolved by reliability standards that do not address reliability problems. The BAAL Field Trial has provided new information
concerning the determination of the contribution of unscheduled energy to transmission reliability. However, the BARC SDT
determined that it was beyond their scope to take action to implement changes in standards or procedures to restrict the
effects of unscheduled energy flows on transmission loading.

Organization

Yes or No

accumulations. All of these issues need time to be vetted by the industry
and the proposed standard modified accordingly before Tacoma Power
would support it.

Question 2 Comment

Unless there is justification we missed, the new definitions should be
removed. With regard to the ACE equation and the WECC ATEC term,
we recommend that the ACE equation be simplified and made such that
it would work with any interconnection. We recommend the term
IATEC be changed to ITC, which would stand for Time Control. The
balancing standards should limit the magnitude of TC to a value such as
20% of Bias. This would work for both the WECC and HQ approach to
controlling time error and assisting in inadvertent interchange
management (WECC). It would also give the Eastern Interconnection a
tool to reduce the number of Time Error Corrections, which will be
important if we want to encourage generators to reduce their
deadbands under BAL-003-1.

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

62

1) SDT believes that the new definitions are needed to provide necessary clarity for the standard.
2) The SDT has modified the definition for Reporting ACE based on the collective comments from the industry.

Response: Thank you for your comments.

IRC-SRC

The Standard Drafting Team appreciates you concern with respect to uncertainty associated with the Field Trial Results.
However, the BAAL has been under Field Trial since July 2005 on the Eastern Interconnection, January 2010 in ERCOT, March
2010 on the Western Interconnection, and January 2011 in Quebec. Voluntary field trials are only as good as the willingness of
the participants. NERC cannot force BAs to participate. The Standard Drafting Team feels that a Field Trial with a duration
approaching eight years should be sufficient to evaluate a standard. Concerning the Field Trial on the Western Interconnection,
the WECC has chosen to take local responsibility for its evaluation and consequently only shared limited data with NERC. The
reports supplied by the WECC have indicated that there are still unknowns associated with the standard, but they have failed to
indicate any significant reliability impacts that can be attributed to the BAAL.

Response: Thank you for your comments.

Organization

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

63

If you have any other comments on BAL-001-2 that you haven’t already mentioned above, please provide them here:

Avista

Organization

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

No

Yes or No

64

Looser AGC control resulting from implementation of BAAL results
in unscheduled flow. Increasing unscheduled flow events
significantly impact each participant in the energy markets.
Schedules are curtailed to accommodate RBC, thus favoring one
form of generation over another. In this case, variable resources
are given an advantage looser control and other parties are
impacted. Although this appears to be an economic issue, any
time energy schedules are curtailed for reliability reasons,
reliability is negatively affected.

Question 3 Comment

A few commenters felt that the SDT was trying to redefine ACE with the proposed definition of Reporting ACE. The SDT stated that
the SDT was not attempting to redefine ACE. The intent was to create a standard term for ACE that was flexible
enough to not require development of a regional standard. The SDT has chosen not to include a generic time error
correction term in the Reporting ACE equation definition. The SDT has modified the definition to address concerns
raised by the industry. In addition, the SDT is proposing to move the definition out of the BAL-001 standard and into
the NERC Glossary as they feel it applies to multiple standards.

Some commenters stated that using a looser ACE control would result in unscheduled energy flows. The SDT explained that
unscheduled energy flows that do not cause reliability problems are not reliability issues. Since these issues are not
reliability problems they should not be resolved by a reliability standard. The BAAL Field Trial has provided new
information concerning the determination of the contribution of unscheduled energy to transmission reliability.
However, the BARC SDT determined that it was beyond their scope to take action to implement changes in standards
or procedures to restrict the effects of unscheduled energy flows on transmission loading.

Summary Consideration: The majority of the commenters provided typographical corrections to the standard and associated
documents.

3.

Yes or No

Question 3 Comment

No
No
No
No
No
No
No
No
Yes

MISO Standards Collaborators

ACES Standards Collaborators

Oklahoma Gas & Electric

Bonneville Power Administration

Salt River Project

PacifiCorp

City of Tallahassee

City of Tallahassee

Manitoba Hydro

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

No

City of Tallahassee

65

(2) Implementation Plan, Regulation Reserve Sharing Group capitalize the words ‘regulating reserve’ because they appear in

(1) Section D, Compliance, 1.1 - the paraphrased definition of
‘Compliance Enforcement Authority’ from the Rules of Procedure
is not the standard language for this section. Is there a reason that
the standard CEA language is not being used?

this is not a yes/no question.

Unscheduled energy flows that do not cause reliability problems are not reliability issues. Since these issues are not reliability
problems they should not be resolved by a reliability standard. The BAAL Field Trial has provided new information concerning
the determination of the contribution of unscheduled energy to transmission reliability. However, the BARC SDT determined
that it was beyond their scope to take action to implement changes in standards or procedures to restrict the effects of
unscheduled energy flows on transmission loading.

Response: Thank you for your comments.

Organization

Yes or No

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Yes

The SDT is using language supplied by NERC legal.
The SDT has made the correction that you have identified.
The SDT has made the correction that you have identified.
The SDT has made the correction that you have identified.
The SDT has made the correction that you have identified.

MRO NERC Standards Review Forum

1)
2)
3)
4)
5)

Response: Thank you for your comments.

Organization

66

2) Additionally, it is not clear how a minute that has bad data
should be treated in the determination of a 30 minute period
under BAAL. This issue needs to be clarified, especially if the
minute with bad data happens to be the first or last minute. The
NSRF is not asking for a change to the standard, just a clear

1) The implementation plan does not include any mention of the
WECC Automatic Time Error Correction in the definition of
Reporting ACE. This deficiency needs corrected as was done in the
BAL-001-2 document. The NSRF believes the drafting team
provided the correct definition in the BAL-001-2 document and
therefore this should not be a significant change to the
implementation plan or standard.

(5) VRF/VSL - capitalize ‘bulk electric system’ in both the High Risk
Requirement and Medium Risk Requirement sections.

(4) Implementation Plan - make same changes to definitions in
Implementation Plan as suggested in Question 1 of this
commenting request.

(3) Implementation Plan, Reporting ACE - capitalize ‘net actual
interchange’ and change ‘scheduled Interchange’ to ‘Net
Scheduled Interchange’.

the Glossary of Terms.

Question 3 Comment

Yes or No

Yes

2) Additionally, it is not clear how a minute that has bad data
should be treated in the determination of a 30 minute period
under BAAL. This issue needs to be clarified, especially if the
minute with bad data happens to be the first or last minute. Xcel
Energy is not asking for a change to the standard, just a clear
statement for the purposes of documenting compliance.

1) The implementation plan does not include any mention of the
WECC Automatic Time Error Correction in the definition of
Reporting ACE. This deficiency needs corrected as was done in the
BAL-001-2 document. Xcel Energy believes the drafting team
provided the correct definition in the BAL-001-2 document and
therefore this should not be a significant change to the
implementation plan or standard.

Yes

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

SPP Standards Review Group

67

On Page 7 of the Background Document, in the 4th line of the 3rd

Replace ‘greater’ with ‘more’ in the Moderate, High and Severe
VSLs for R2.

Add an ‘s’ to ‘period’ in the 2nd line of 4.1.2 in the Applicability
Section.

1) The SDT has made the correction that you have identified.
2) The SDT has added clarifying language to Attachment 2 to address your concern.

Response: Thank you for your comments.

Xcel Energy

Question 3 Comment
statement for the purposes of documenting compliance.

1) The SDT has made the correction that you have identified.
2) The SDT has added clarifying language to Attachment 2 to address your concern.

Response: Thank you for your comments.

Organization

Yes or No

Question 3 Comment
paragraph, replace ‘that’ with ‘than’ in front of CPS1.

Duke Energy

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Yes

68

Though Duke Energy supports the adoption of the BAAL; it’s not
clear why all of the other changes to the standard are needed, nor
is it clear how these changes respond to FERC directives. We
believe that it should be mentioned that the BAAL addresses the
FERC directive to develop a standard addressing the large loss of
load - the BAAL measure will ensure appropriate response to any
event causing the Balancing Authority’s ACE to exceed its BAAL
(see comments to BAL-013 for further details). Duke Energy
agrees with the proposed change to the BAAL equation to
accommodate Time-Error Corrections by placing Scheduled
Frequency in the numerator and denominator in place of 60 Hz;

Duke Energy does not support the definition of Reporting ACE as
written. We believe that “ACE” should be defined as “The
difference between the Balancing Authority’s net actual
Interchange and its scheduled Interchange, plus its Frequency Bias
obligation, plus any known meter error plus Automatic Time Error
Correction (ATEC - If operating in the Western Interconnection
and in the ATEC mode)”; followed with the equation shown and
the details of the variables. “Reporting ACE” should be defined
simply as the “The scan rate values of a Balancing Authority’s
ACE”.

The SDT has made the correction in the Background Document that you have identified.

The SDT does not see any difference between using the work “greater” versus “more” and therefore has decided to keep the
word greater.

The SDT has made the correction in the Applicability Section that you have identified.

Response: Thank you for your comments.

Organization

Yes or No

however it is not clear why Balancing Authorities under the Field
Trial have not yet been afforded the opportunity to incorporate
the same change in the BAAL calculation in their tools. Duke
Energy would support allowing the Balancing Authorities under
the Field Trial to make the appropriate changes in their tools to be
consistent with the BAAL equation as proposed, and would
support the drafting team updating the tools on the NERC Field
Trial website to be consistent with the current BAL-001-2 posted.

Question 3 Comment

Yes

Yes

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Idaho Power Company

Response: Thank you for your comment.

Exelon

69

I believe that operating under the BAAL does not pose a threat to
reliability and could help mitigate variable resource integration
provided that BAs do not stress the limits during normal
operations. If BAs could be encouraged to follow expected
changes in system demand reasonably close during normal
conditions then the system could more readily absorb unexpected
events. However, I'm not sure how this can be addressed within a
standard.

Exelon is basically fine with structure.

The SDT agrees with your comment concerning the field trial. The SDT will look into the concern you have identified.

The SDT is not attempting to redefine ACE. The intent was to create a standard term for ACE that was flexible enough to not
require development of a regional standard. The SDT has chosen not to include a generic time error correction term in the
Reporting ACE equation definition. The SDT has modified the definition to address concerns raised by the industry. In addition,
the SDT is proposing to move the definition out of the BAL-001 standard and into the NERC Glossary as they feel it applies to
multiple standards.

Response: Thank you for your comments.

Organization

Yes

Yes or No

The Frequency Trigger Limit is set too tight at 3 standard
deviations. This causes too many initial exceedences of BAAL as
revealed in the field tests. This prompts BAs to wait until enough
of them disappear by themselves to make it feasible to address all
of the remainder. But, by waiting, the BA is failing to address the
remainder early enough before they become outright violations.
Instead, it would be better for reliability to raise the Frequency
Trigger Limit to, say, 4 or 5 standard deviations to reduce the
number of initial exceedences of BAAL to the point where it is
feasible to address ALL of them immediately. What reliability is
gained by a tighter limit that is feasible only if the BAs wait to
address any and all of the exceedences? Furthermore, no
legitimate statistical justification was ever provided for the tight 3standard-deviations Frequency Trigger Limit. The very flawed
attempt to provide such a justification led to rejection of the first
version of this standard put out for balloting. No further formal
technical justification was thereafter developed on which to base
that or a wider limit, despite acknowledgement for a time on the
drafting team that it was needed.

Question 3 Comment

Yes

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

seattle city light

70

The Guidelines document purported to address issues such as
those discussed in question 2 above will not be available for
review until summer 2013. Lacking such a document, Seattle City

The drafting team has considered other alternative approaches and has selected the 3 epsilon model as the best and fairest
model for the requirement. BAAL was designed to provide for better control by allowing power flows that do not have a
detrimental effect on reliability but restrict those that do have a detrimental effect on reliability.

Response: Thank you for your comments.

Keen Resources Ltd.

Response: Thank you for your comments.

Organization

Yes or No

Yes

The High Frequency Limit (FTLhigh) calculated as Fs + 3Ô 1i
should be changed to Fs + 4Ô 1i

Yes

Yes

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

American Electric Power

Response: Thank you for your comments.

Tucson Electric Power Co

71

We would encourage the drafting team to provide Generator
Operators with the appropriate requirements to support the
Balancing Authorities. As currently drafted, the Balancing
Authority may be the sole entity responsible for meet the
obligations of the standard, and yet it does not have direct control
over the Generator Operator to ensure the BA receives what is
needed. At the least, the BA might need some sort of recourse
specified in the event a Generator Operator is not acting in a
cooperative manner (for example, a Generator Operator who
refuses to adhere to their agreed-upon schedule in real time, but
is not penalized because they integrate over the hour).

Using the newly-defined term Reporting (ATEC) ACE is a positive
change. Using Scheduled Frequency instead of 60Hz in the BAAL
calculation is also a positive change.

The SDT believes that the High Frequency Limit is calculated properly as currently written in the standard. Without further
information as to why you believe it is incorrect, the SDT cannot address your issue.

Response: Thank you for your comments.

NextEra Energy

Question 3 Comment
Light cannot support this draft of BAL-001-2.

The Guidelines Document is anticipated to be posted by July 19, 2013.

Response: Thank you for your comments.

Organization

Yes or No

Question 3 Comment

Yes

Energy Mark, Inc.

: We do not believe it is appropriate to include a region or
interconnection specific definition in a continent-wide standard.
However, we would not object to including a generic term for
time-control adjustment.These comments were also supported by
Ron Carlsen with Southern Company.The comments expressed
herein represent a consensus of the views of the above named
members of the SERC OC Standards Review Group only and
should not be construed as the position of the SERC Reliability
Corporation, or its board or its officers.

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Portland General Electric Company

Response: Thank you for your comments.

PPL NERC Registered Affiliates

72

PGE is generally supportive of the underlying goal of this standard
revision - increased coordination between BAs for efficiently and
reliably, meeting Control Performance Standards through the
development of a Regulation Reserve Sharing Group, or other yet

LGE and KU Services is a participant in the BAAL Field Test and
support the implementation of the BAAL standard

The SDT is only attempting to recognize the approved variance that was granted to the WECC.

Response: Thank you for your comments.

SERC OC Standards Review Group

Yes

EnerVision, Inc.

The SDT understands your concern but believes that it is outside the scope of this project. The SDT believes that this is a
commercial issue that should be addressed by FERC.

Response: Thank you for your comments.

Organization

Yes or No

to be named program. However, PGE is concerned the proposed
standard does not adequately address the reliability concerns
associated with unscheduled flow and degraded frequency
response metrics that have been witnessed with the current
WECC Reliability Based Control pilot program. PGE believes the
unique physical transmission properties of the Western
Interconnect dictate a need for increased consideration of
reliability protections for our region prior to the adoption of new
nation-wide standards.

Question 3 Comment

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Powerex Corp.

73

1) In Order No. 890, the Federal Energy Regulatory Commission
(FERC or the Commission) recognized the potential for inadvertent
energy flows between adjacent BAs to both jeopardize reliability
and to cause undue harm to customers on the grid. Such
inadvertent energy flows are driven by the size of each BAAs ACE,
but are primarily contained by CPS2 under the current BAL-001.
FERC also made it clear that it was inappropriate for generators

Powerex believes that the reliability issues with the current draft
standard have not been adequately addressed by the drafting
team. The reliability issues that have been previously submitted
by commenters raised valid concerns, and the drafting team has
not addressed those specific concerns in their responses.
Powerex submits the following subsequent comments:

Unscheduled energy flows that do not cause reliability problems are not reliability issues. Since these issues are not reliability
problems they should not be resolved by a reliability standard. The BAAL Field Trial has provided new information concerning
the determination of the contribution of unscheduled energy to transmission reliability. However, the BARC SDT determined
that it was beyond their scope to take action to implement changes in standards or procedures to restrict the effects of
unscheduled energy flows on transmission loading.

Response: Thank you for your comments.

Organization

Organization

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Yes or No

74

2) Various entities have also expressed concerns regarding the
reliability impacts of inadvertent or unscheduled flows. The issues
experienced by entities during the Field Trial were provided in the
previous comment period, but the drafting team has failed to
address the comments adequately. Furthermore, the drafting
team ignored the concerns and provided a generic response to
commenters from NE ISO, WECC, Tucson, APS, BPA and NPPD.
These concerns regarding the BAAL standard include comments
such as:a. Reliability concerns over BAAL limits not accounting for
large ACE excursions b. Increase in transmission limit exceedances
c. Interconnection exposed due to the lack of ACE bounding d. CPS
2 is a more reliable metrice. Allows for more unscheduled power
flows and amount of unscheduled interchange a BA can have is
not cappedf. WECC average frequency deviation has been
increasingg. Elimination of CPS2 has a detrimental impact on

within a BAA to “dump power on the system or lean on other
generation...The tiered imbalance penalties adopted in the Final
Rule generally provide a sufficient incentive not to engage is such
behavior”The proposed standard will allow entities to create
deliberate inadvertent flows within the standards boundaries,
without regard to the impacts and which could lead to
exceedances in SOL due to large ACEs. The proposed
performance standard does not address the potential for a single
BA to lean on the grid with deliberate unscheduled energy flows
or inadvertent energy, taking any accumulated benefits for itself
and harming other entities on the grid. The detrimental impacts of
deliberate inadvertent flows to load customers and transmission
customers on the grid could be substantial when large ACE
deviations cause transmission limit exceedances. It is imperative
that the drafting team address this issue in the standard.

Question 3 Comment

Organization

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Yes or No

75

3) After reviewing the previous comments and responses, it has
become abundantly clear that the drafting team chose to respond
to commenters with generic statement such as “The drafting team
conducts a monthly call to review the results from the BAAL field
trial. There have not been any reliability issues raised by any RC
during these calls. The drafting team encourages BA’s and RC’s to
share any specific occurrences that they feel have reliability
impacts as a result of operating under BAAL.”, but did not
specifically address, revise or enhance the proposed standard
based on the comments.These generic statements are not
appropriate by a drafting team and could be considered as
dismissive.. The drafting team seems to be suggesting that the
“monthly call” mentioned in the drafting team’s response is the
only forum where reliability concerns need to be addressed. As an
example, WECC submitted comments and provided information
on RC actions and asked for the drafting team to remedy the issue
in the standard, and I quote “During Phase 3, the Reliability
Coordinators (RC) reported several SOL exceedance associated
with high ACE. The SOL exceedances were mitigated when RCs
requested the high ACE value to be reduced to L10.The SDT must
address transmission loading issues caused by high ACE.”The
drafting team did not adequately address this issue, which was
raised by a regional entity, and responded by issue a generic
statement that since this issue wasn’t discussed on the monthly
phone call that these issues or experiences in WECC are not true
reliability issues. It is imperative that the drafting team revisit all

reliability h. Leads to transmission constraints and requires TOPs
and RCs to restrict the unscheduled flows on the system due to a
BA unilaterally over or under generatingi. WECC has experienced
many SOL violations due to Large ACEs

Question 3 Comment

Organization

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Yes or No

76

5) Powerex believes that the standard should have a BAALHigh
and BAALLow in place at all time in order to manage ACE

4) Powerex believes that the current field trial has not proven to
be more reliable, and it is imperative that the issues surrounding
the increases in frequency error, exceedance of SOL and
transmission limits be addressed. There has been no comparison
or evidence provided that shows that the proposed standard is
superior in reliability than CPS2. Several commenters have raised
concerns with the elimination of CPS2, and impacts associated
with the increase of frequency error and unscheduled interchange
due to large ACE deviations, which pose a greater risk to reliability
than the current CPS2 requirement. The drafting team cannot
provide a generic statement that “BAAL was designed to provide
for better control by allowing power flows that do not have a
detrimental effect on reliability but restrict those that do have a
detrimental effect on reliability” without providing any evidence
or data to test the validity of those statements. The drafting team
has not provided any supporting evidence or data that would
validate such a generic statement, nor has it provided any benefits
that were realized during the field trial and resulted in enhanced
reliability. On the contrary, WECC has experienced a degradation
of reliability measures, impacts to commercial transmission
customers, as well as reliability issues that required RC
intervention during the field trial. Those detrimental effects of
the proposed standard cannot be offset by the drafting team
providing generic and unsupported statements.

those comments that have been received and make appropriate
revisions, and additions to the standard address the reliability
concerns raised by the entities regarding SOL exceedance,
transmission loading, and unscheduled flow issues.

Question 3 Comment

Organization

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Yes or No

77

7) The drafting team has not adequately addressed the issue of
“sawtoothing” operations as exhibited by entities during the field
trial. Sawtoothing can be described as entities that are allowing
ACE to be unlimited for 29 minutes and then be brought under
BAAL limits for 1 minute. This type of behavior is shown in the
NERC reports posted on the field trial. The drafting team is
hedging that entities will not operate in this manner after the field
trial due to higher operation and compliance risk to entities.
However, the NERC field trial should have created disincentives to
not allow such behavior during the onset of the field trial, and
requirements should have been adopted to discourage behavior
that poses reliability risks.

b) Why have the results for the field trial not been updated
on the project page on the NERC website since June 2012?

a) Why have the field trial results not been provided to
NERC membership prior to ballot body?

6) The drafting team stated in their response to previous
comments that “The drafting team will be preparing a report
based on the field trial results that will be posted prior to the FERC
filing for this draft standard”. Powerex poses two questions to the
drafting team:

deviations that may jeopardize reliability through unscheduled
flows, which can lead to exceedance of SOL and transmission
limits. For example, WECC membership found it appropriate to
apply a limit of 4 times a BA’s L10. This mechanism provides
flexibility to handle interconnection frequency while not allowing
ACE deviations to become so significant that BA flows negatively
impact the transmission system.

Question 3 Comment

Yes or No

Question 3 Comment

Tacoma Power does not support a standard that institutionalizes a
control methodology that is still in the development stage and is
not supported by actual data. Thank you for consideration of our
comments.

The latest changes to the VSLs for R2 made them more confusing.
We would suggest re-wording them to state, for example: “The
Balancing Authority exceeded its clock†minute BAAL for more
than 30 consecutive clock minutes and for less than or equal to 45
consecutive clock minutes.”

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

78

The SDT believes that the wording presently used in the VSLs provides the necessary clarity. In addition, your concern that the
VSLs are confusing has not been supported by the rest of the industry.

Response: Thank you for your comments.

Texas Reliability Entity

The SDT does not agree that the requirements in BAL-001-2 are a control methodology.

Response: Thank you for your comments.

Tacoma Power

With the change in SDT leadership, some of the field trial data was not getting posted. The data is now posted and the SDT
leadership is attempting to post the information on a monthly basis.

The BARC SDT was able to determine that BAAL provides a guarantee that if all BAs are operating within their BAAL the
interconnection frequency error will remain less than the frequency trigger limit.

Unscheduled energy flows that do not cause reliability problems are not reliability issues. Since these issues are not reliability
problems they should not be resolved by a reliability standard. The BAAL Field Trial has provided new information concerning
the determination of the contribution of unscheduled energy to transmission reliability. However, the BARC SDT determined
that it was beyond their scope to take action to implement changes in standards or procedures to restrict the effects of
unscheduled energy flows on transmission loading.

Response: The SDT thank you for your comments.

Organization

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

END OF REPORT

79

Consideration of Comments

Project 2010-14.1 (BAL-002-2)
Phase 1 of Balancing Authority Reliability-based Controls: Reserves
The Balancing Authority Reliability-based Controls: Reserves Drafting Team thanks all commenters who
submitted comments on the proposed revisions to BAL-001-2 Real Power Balancing Control
Performance. These standards were posted for a 45-day public comment period from March 12, 2013
through April 25, 3013. Stakeholders were asked to provide feedback on the standards and associated
documents through a special electronic comment form. There were 55 sets of comments, including
comments from approximately 179 different people from approximately 108 companies representing
all of the 10 Industry Segments as shown in the table on the following pages.
Based on industry comments the drafting team made the following clarifying modifications to the
proposed standard and associated documents.
Modified the definition for a Balancing Contingency Event to provide additional clarity.
Modified the definition for a Reportable Balancing Contingency Event to use Interconnection
specific thresholds instead of a continent wide threshold.
Modified Requirements R1 and R2 to provide additional clarity.
Modified the VSL for Requirement R1 to provide additional clarity.
Modified the Background Document to provide additional clarity.
There were a couple of minority issues that the team was unable to resolve, including the following:
A couple of stakeholders felt that the proposed BAL-001-1 draft standard was sufficient to cover
a DCS event and that BAL-002 could be deleted. The drafting team appreciated their comments
and recognized the potential overlap of BAL-001 and BAL-002. However, the drafting team did
not believe the time was right for combining the two standards. The drafting team believes that
in order to advance this process of combing the two standards these two proposed standards
need to move forward. The drafting team supports moving this issue forward and is committed
to submit a SAR supporting this concept for future development.
Some stakeholders questioned why the drafting team was not using the term Reportable
Disturbance. The drafting team explained that the term Disturbance as defined by the NERC
Glossary of terms is extremely broad and not specific. The Term Balancing Contingency Event
was defined to allow the drafting team to be more specific as to what should be considered for
the purposes of this standard.
A couple of stakeholders wanted the drafting team to use BAAL as the measure for performance
in this standard. The drafting team explained that they considered using the approach of BAAL
as the measure for performance in this standard but chose the present method since concerns
other than frequency performance may need to be addressed. There is also a compelling
interest in measuring the adequacy of reserve.

A few stakeholders felt that there should only be a statement in the applicability section stating
that this standard did not apply to a BA when it was in an EEA Level 2 or 3. The drafting team
explained that they included it in both the applicability section and in the requirement to assure
no misinterpretation by the auditors.
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 Vice President and Director of Standards, Mark Lauby, at 404-446-2560 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.1

1

The appeals process is in the Standard Processes Manual: http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

2

Index to Questions, Comments, and Responses

1.

The BARC SDT has modified the definition for Balancing Contingency Event based on comments
received from the industry. Do you agree that the modifications provide addition clarity? If not,
please explain in the comment area below. ................................................................................. 1513

2.

The BARC SDT has modified the current definition for Contingency Reserve. Do you agree that the
modified definition provides for greater clarity? If not, please explain in the comment area below.
2523

3.

The BARC SDT has created a definition for Reserve Sharing Group Reporting ACE. Do you agree
with this definition? If not, please explain in the comment area below. ..................................... 3331

4.

The BARC SDT has added language to the proposed requirements in the standard and to the
definition for Contingency Reserve to resolve any conflicts between this standard and the EOP
standards. Do you agree that this modification was necessary and that any possible issues are now
resolved? If not, please explain in the comment area. ................................................................. 3937

5.

The BARC SDT has developed Requirement R2 which requires entities to have Contingency
Reserve at least equal to its MSSC. This requirement was added to address, in conjunction with
Requirement R1, the FERC Directive for a continent wide Contingency Reserve policy. Do you
agree that this addresses the FERC Directive? If not, please explain in the comment area. ....... 4644

6.

The BARC SDT has assigned both Requirement R1 and Requirement R2 a “medium” VRF. Do you
agree with the proposed VRF? If not, please explain in the comment area below. ..................... 6664

7.

The BARC SDT has assigned both Requirement R1 and Requirement R2 a Time Horizon of “Realtime Operations”. Do you agree with the Time Horizon the SDT has chosen? If not, please explain
in the comment area below. ......................................................................................................... 7169

8.

The BARC SDT has developed VSLs for Requirement R1 and Requirement R2. Do you agree with
the VSLs in this standard? If not, please explain in the comment area. ....................................... 7573

9.

The BARC SDT has made significant modifications to the Background Document based on industry
comments received. Do you agree that these modifications provide additional clarity as to the
development of this standard? If not, please explain in the comment area. ............................... 8179

10. If you are not in support of this draft standard, what modifications do you believe need to be
made in order for you to support the standard? Please list the issues and your proposed solution
to the issue. ................................................................................................................................... 8987

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

3

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

4

Organization

Greg Campoli

Sylvain Clermont

Chris de Graffenried Consolidated Edison Co. of New York, Inc.

Gerry Dunbar

Mike Garton

Peter Yost

Michael Jones

3.

4.

5.

6.

7.

8.

9.

NPCC 2

NPCC 10

Region Segment Selection

National Grid

Consolidated Edison Co. of New York, Inc.

Dominion Resources Services, Inc.

Northeast Power Coordinating Council

Hydro-Quebec TransEnergie

NPCC 1

NPCC 3

NPCC 5

NPCC 10

NPCC 1

NPCC 1

New York Independent Electricity System Operator NPCC 2

Independent Electricity System Operator

New York State Reliability Council, LLC

Carmen Agavriloai

Additional Organization

Northeast Power Coodinating Council

Alan Adamson

Guy Zito

2.

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

Hydro-Quebec TransEnergie

Ontario Power Generation, Inc.

Utility Services

National Grid

New York Power Authority

New Brunswick System Operator

Orange and Rockland Utilities

Russel MountjoySecretary

17. Si-Truc Phan

18. David Ramkalawan

19. Brian Robinson

20. Brian Shanahan

21. Wayne Sipperly

22. Donald Weaver

23. Ben Wu

2.

MRO NERC Standards Review Forum

NPCC 1

NPCC 2

NPCC 5

NPCC 1

NPCC 8

NPCC 5

NPCC 1

MRO

MRO

MRO

MRO

MRO

MRO

MRO

MRO

MRO

MRO

MRO

MRO

MRO

MRO

1, 3, 5

3, 4, 5, 6

1, 3, 5, 6

4

1, 3, 5, 6

1, 3, 5, 6

2

1, 3, 5

4

3, 4, 5, 6

1, 6

1, 3, 5, 6

1, 3, 5, 6

1, 3, 5, 6

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

NPPD

GRE

MISO

WPS

Mike Brytowski

9.

14. Tony Eddleman

Marie Knox

8.

OTP

13. Tom Breene

Lee Kittleson

7.

ALTW

MGE

MEC

Ken Goldsmith

6.

RPU

Joseph Depoorter

5.

WAPA

12. Terry Harbour

Jodi Jensen

4.

BEPC

MPC

11. Scott Nickels

Dave Rudolf

3.

MPW

Dan Inman

2.

Xcel

10. Scott Bos

Alice Ireland

1.

Additional Member Additional Organization Region Segment Selection

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 5

Northeast Power Coordinating Council

New Brunswick Power Transmission

12. Randy MacDonald

15. Lee Pedowicz

PSEG Power LLC

11. Christina Koncz

NPCC 1

Organization

14. Silvia Parada Mitchell NextEra Energy, LLC

Hydro One Networks Inc.

Commenter

10. David Kiguel

Group/Individual

X

1

X

2

X

3

X

4

X

5

X

6

6

7

8

Registered Ballot Body Segment
9

X

10

Group

Westar Energy

Sunflower Electric Power Corporation SPP

5. Bryan Taggart

6. Allan George

1

1, 3, 5, 6

1, 3, 5, 6

SERC OC Standards Review Group

SPP

SPP

1

1, 3, 5, 6

1, 3, 5, 6

David Jendras

Kevin Johnson

Colby Brett Bellville Duke

Mike Lowman

Tom Pruitt

Terry Bilke

Brad Gordon

3.

4.

5.

6.

7.

8.

9.

Georiga Power Company SERC

PowerSouth

Power South

SCE&G

SCPSA

Progress Energy

SCPSA

SCPSA

SIPC

12. Phil Whitmer

13. Bill Thigpen

14. Tim Hattaway

15. Troy Blalock

16. Glenn Stephens

17. Sammy Roberts

18. Rene Free

19. Tom Abrams

20. John Rembold

1

1, 3, 5, 6

1, 3, 5, 6

1, 3, 5, 6

1, 3, 5, 6

1, 3, 5, 6

1, 5

1, 5

3

1, 3, 5, 6

1, 3, 6

2

2

1, 3, 5, 6

1, 3, 5, 6

1, 3, 5, 6

1

1, 3

4

3, 5, 6, 1

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

SERC

SERC

SERC

SERC

SERC

SERC

SERC

SERC

SERC

JGE-KU

11. Wayne Van Liere

SERC

Entergy

SERC

SERC

SERC

SERC

SERC

SERC

SERC

SERC

SERC

10. Jim Case

PJM

MISO

Duke

Duke

Big Rivers

Ameren

AMEA

Ray Phillips

2.

AECI

Jeff Harrison

1.

Additional Member Additional Organization Region Segment Selection

Stuart Goza

Westar Energy

4. Kevin Nincehelser

Group

Sunflower Electric Power Corporation SPP

3. Jerry McVey

SPP

SPP

Region Segment Selection

Westar Energy

4.

Organization

SPP Standards Review Group

Westar Energy

Additional Organization

Robert Rhodes

2. Tiffany Lake

Additional Member

Commenter

1. Bo Jones

3.

Group/Individual

X

1

X

2

X

3

4

X

5

X

6

7

7

8

Registered Ballot Body Segment
9

10

Southern

Southern

Southern

TVA

paul haase

22. Jimmy Cummings

23. M. D. Tucker

24. Randy Hubbert

25. Kelly Casteel

5.

seattle city light

seattle city light

seattle city light

3. hao li

4. mike haynes

5. dennis sismaet

Duke Energy

Duke Energy

3. Dale Goodwine

4. Greg Cecil

RFC

SERC

FRCC

RFC

Iberdrola USA

Group

PPL NERC Registered Affiliates
RFC

PPL Generation, LLC on behalf of Supply NERC Registered Affiliates RFC

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

X

X

X

X

1

2

5

1

Region Segment Selection

2. Annette Bannon

Additional Organization

Brent Ingebrigtson

PPL Electric Utilities Corporation

Additional Member

1. Brenda Truhe

9.

New York State Electric & Gas NPCC 1

NPCC 1

Central Maine Power

Region Segment Selection

2. Raymond Kinney

Additional Organization

3, 4, 5

3, 4, 5

1. Joseph Turano

Additional Member

John Allen

RFC

2. Dan Herring

Group

RFC

1. Al Eizans

8.

DTE Electric

6

5

3

1

Additional Member Additional Organization Region Segment Selection

Kent Kujala

Duke Energy

2. Lee Schuster

Group

Duke Energy

1. Doug Hils

7.

Duke Energy

WECC 6

WECC 5

WECC

WECC 3

WECC 1

Additional Member Additional Organization Region Segment Selection

Greg Rowland

seattle city light

2. dana wheelock

Group

seattle city light

1. pawel krupa

6.

1, 3, 5, 6

1, 5

1, 5

1, 5

1, 5

seattle city light

SERC

SERC

SERC

SERC

SERC

Organization

Additional Member Additional Organization Region Segment Selection

Group

Southern

Commenter

21. Cindy Martin

Group/Individual

X

X

X

X

3

X

X

4

X

X

X

X

5

X

X

X

6

8

7

8

Registered Ballot Body Segment
9

10

Fort Pierce Utility Authority FRCC

Ocala Utility Services

5. Cairo Vanegas

6. Randy Hahn

3

4

3

3

MISO Standards Collaborators

FRCC

FRCC

3

4

Group

Ronald L Donahey

NIPSCO

RFC

Tampa Electric Company

6

5

3. James Rocha

14.

Group

ERCOT

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

H. Steven Myers

Group
Pamela R. Hunter
No additional members listed.

6

6

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

6

2. Benjamin Smith III

13.

1

1. Sara E Young

Additional Member Additional Organization Region Segment Selection

12.

1. Joe O'Brien

Additional Member Additional Organization Region Segment Selection

Marie Knox

City of Clewiston

4. Lynne Mila

Group

Kissimmee Utility Authority FRCC

3. Greg Woessner

11.

Lakeland Electric

2. Jim Howard

FRCC

City of New Smyrna Beach FRCC

1. Tim Beyrle

Additional Member Additional Organization Region Segment Selection

Florida Municipal Power Agency

WECC 6

9.

Frank Gaffney

RFC

8.

Group

SPP

7.

10.

SERC

6.

6

NPCC 6

6

MRO

5.

PPL EnergyPlus, LLC

4. Elizabeth Davis

Organization

WECC 5

Commenter

3.

Group/Individual

X

X

X

1

X

X

2

X

X

X

3

X

4

X

X

X

5

X

X

X

6

9

7

8

Registered Ballot Body Segment
9

10

Commenter

Organization

ERCOT

ERCOT

ERCOT

ERCOT

4. Ken McIntyre

5. Stephen Solis

6. Vann Weldon

7. Jeff Healy

Dennis Chastain

1, 3, 5, 6

Tennessee Valley Authority

MRO

SERC

4. Marjorie Parsons

Oklahoma Gas & Electric

6

5

3

1

IRC-SRC

5

3

1

2

NPCC 2

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

NYISO

NPCC 2

NPCC 2

RFC

4. Greg Campoli

IESO

2. Ben Li

3. Kathleen Goodman NEISO

PJM

1. Stephanie Monzon

Additional Member Additional Organization Region Segment Selection

Terry Bilke

Oklahoma Gas & Electric SPP

3. Leo Staples

Group

Oklahoma Gas & Electric SPP

2. Donald Hargrove

18.

Oklahoma Gas & Electric SPP

1. Terri Pyle

Additional Member Additional Organization Region Segment Selection

Terri Pyle

SERC

3. David Thompson

Group

SERC

2. Ian Grant

17.

SERC

1. DeWayne Scott

Additional Member Additional Organization Region Segment Selection

Group

Great River Energy

4. Michael Brytowski

16.

Southwest Transmission Cooperative WECC 1

3. John Shaver

WECC 4, 5

Arizona Electric Power Cooperative

2. John Shaver

1

Region Segment Selection

ACES Standards Collaborators

Sunflower Electric Power Corporation SPP

Additional Organization

ERCOT 2

ERCOT 2

ERCOT 2

ERCOT 2

ERCOT 2

ERCOT 2

ERCOT 2

1. Megan Wagner

Additional Member

Jason Marshall

ERCOT

3. Matt Stout

Group

ERCOT

2. Sandip Sharma

15.

ERCOT

1. Matt Morais

Additional Member Additional Organization Region Segment Selection

Group/Individual

X

X

1

X

2

X

X

3

4

X

X

5

X

X

10

6

7

8

Registered Ballot Body Segment
9

10

Jamison Dye

Commenter

2

Bonneville Power Administration

WECC

SPP

Organization

WECC 5
WECC 5

5. Pam VanCalcar

6. Fran Halpin

Individual

Individual

Individual

Individual

Individual

Individual

Individual

Individual

Individual

Individual

22.

23.

24.

25.

26.

27.

28.

29.

30.

31.

Michael Falvo

Individual

Individual

Individual

34.

35.

36.

Alliant Energy

Energy Mark, Inc.

Independent Electricity System Operator

JDRJC Associates LLC
Idaho Power Company

SMUD

ReliabilityFirst

NV Energy

Manitoba Hydro

Avista

Tucson Electric Power

EnerVision, Inc.

Alberta Electric System Operator

PJM Interconnection, LLC

PacifiCorp

Salt River Project

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Kenneth A Goldsmith

Howard F. Illian

Jim Cyrulewski
Greg Travis

Joe Tarantino

Anthony Jablonski

Rich Salgo

Nazra Gladu

Rich Hydzik

John Tolo

Tom Siegrist

Ken Gardner

Stephanie Monzon

Ryan Millard

Bob Steiger

Individual
33. Individual

32.

Individual

21.

Arizona Public Service Company

WECC 1

4. Don Watkins

Janet Smith, Regulatory
Affairs Supervisor

WECC 1

3. Ayodele Idowu

Individual

WECC 1

2. Dave Kirsch

20.

WECC 1

1. Bart McManus

Additional Member Additional Organization Region Segment Selection

Group

CAISO

6. Ali Miremadi

19.

SPP

5. Charles Yeung

Group/Individual

X

X

X

X

X

X

X

X

X

X

1

X

X

X

2

X

X

X

X

X

X

X

X

3

X

X

4

X

X

X

X

X

X

X

X

5

X

X

X

X

X

X

11

6

X

7

X

8

Registered Ballot Body Segment
9

X

10

Individual

Individual

Individual

Individual

Individual

Individual

Individual

Individual

Individual

43.

44.

45.

46.

47.

48.

49.

50.

51.

55.

54.

53.

Individual

Individual

Individual

Individual

Individual

42.

52.

Individual

41.

Xcel Energy

NIPSCO
Massachusetts Municipal Wholesale Electric
Company

Exelon

Hydro-Quebec TransEnergie

FMPP

Modesto Irrigation District

Platte River Power Authority

Seminole Electric Cooperative, Inc.

Keen Resources Ltd.

NextEra Energy

Entergy Services, Inc. (Transmission)

Texas Reliability Entity

Tacoma Power

Public Service Enterprise Group

American Electric Power

Portland General Electric Company
ISO New England Inc.

City of Austin dba Austin Energy

Organization

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Alice Ireland

David Gordon

William O. Thompson

Si Truc PHAN
John Bee on Behalf or
Exelon and its Affiliates

Thomas Washburn

Spencer Tacke

Christopher Wood

Steven Wallace

Robert Blohm

Brian Murphy

Oliver Burke

Don Jones

Keith Morisette

John Seelke

Thad Ness

Individual

40.

Andrew Gallo

Angela P Gaines
Kathleen Goodman

Individual

Commenter

Individual
39. Individual

38.

37.

Group/Individual

X

X

X

X

X

X

X

X

X

X

X

1

X

2

X

X

X

X

X

X

X

X

X

X

X

X

3

X

X

X

X

4

X

X

X

X

X

X

X

X

X

X

X

X

X

5

X

X

X

X

X

X

X

X

X

X

X

X

12

6

7

X

8

Registered Ballot Body Segment
9

X

10

Agree
Agree
Agree
Agree
Agree
Agree

Agree

Agree

Agree
Agree

Iberdrola USA

Tampa Electric Company

Tennessee Valley Authority

JDRJC Associates LLC

Alliant Energy

City of Austin dba Austin
Energy

Public Service Enterprise
Group

Entergy Services, Inc.
(Transmission)

Platte River Power Authority

FMPP

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Agree

DTE Electric

Summary Consideration:

FMPA
13

Public Service Company of Colorado (Xcel Energy)

SERC OC Standards Review Group

PJM Interconection

ERCOT

MRO NSRF

Midwest ISO

SERC OC Standards Review Group

Duke Energy

NPCC

MISO

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).

Agree

Massachusetts Municipal
Wholesale Electric Company

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Agree

NIPSCO

14

Northeast Power Coordinating Council, Inc
(NPCC)ISO New England, Inc.

MISO

The BARC SDT has modified the definition for Balancing Contingency Event based on comments received from the industry. Do
you agree that the modifications provide addition clarity? If not, please explain in the comment area below.

No

Yes or No

Question 1 Comment

15

Additionally, an entity may not know that the loss is due to a loss of
transmission. We would suggest: ‘Sudden, unexpected loss of an import

Also, there is a timing element associated with Subsection B which could
cause conflict with the wording in B. Requiring a sudden loss of import by
the loss of a transmission element, implies that the loss of import would be
sudden. It may or may not be. It depends on when the loss is reflected in
schedules.

Similar changes need to be made to Subsections B and C.

We would suggest incorporating the concept of an unexpected event with
the loss itself rather than tying it to the change in ACE. For example in
Subsection A, we would propose: ‘Sudden, unexpected loss of generation...’

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

SPP Standards Review Group

Organization

One commenter suggested that the SDT incorporate the concept of an unexpected event with the loss itself rather than tying it to the
change in ACE. The SDT explained that the use of resource loss for determining an event size and ACE in determining
recovery from an event has long been used by the industry and is in both the definition of a Disturbance and
Reportable Event. The drafting team chose not to alter this practice. Additionally this compliments all the subsections
of the definition, such that there is not a Balancing Contingency Event without a change in ACE.

A couple of commenter felt that the definition was not complete since it did not specify a unit’s failure to start. The SDT stated that
an earlier version of the definition did contain language recognizing a unit’s failure to start. The SDT removed this due
to overwhelming objection from the industry for including this term.

Summary Consideration: Some commenters were confused as to what was meant by the term “loss of a known load”. The SDT
explained that they had removed this term and added clarifying language.

1.

Yes or No

In Subsection C we suggest: ‘Sudden unexpected loss of a known load...’The
term ‘responsible entity’ is not capitalized in the definition but is in the
standard. Should it be in the definition?

that causes a change to the responsible entity’s ACE.’

Question 1 Comment

No

Seattle City Light considers the definition of Balancing Contingency Event
proposed in this draft of BAL-002-2 to be incomplete in that it does not
recognize the failure of a unit to start as an “event.” Seattle recommends
revising the definition to read: “A.a.i. Unit Tripping or failure to start at the
scheduled time."

Duke Energy

16

o Regarding Subsection “C.”, it is also not clear what is meant by the
“sudden loss of a known load used as a resource”. Is the team referring to
an interruptible load resource, fully loaded and counted on for provision of
contingency reserve? If so, would the sudden loss of the resource mean
that the load is inadvertently interrupted causing high ACE? We’re not
aware of a proven reliability risk that warrants a 15-minute recovery period
from a high ACE. Or, is the team referring to an interruptible load resource

o The definition is too broad. Using the phrase “or any series of such
otherwise single events” leaves much open to interpretation. In many
cases it will not be clear when the 15-minute clock has been triggered.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

No

Response: Thank you for your comment. Based on the initial posting, the SDT removed “failure to start” from the definition due to
the overwhelming objection from the industry on including this within the definition.

seattle city light

Response: Thank-you for your comments. The use of resource loss for determining an event size and ACE in determining recovery
from an event has long been used by the industry and is in both the definition of a Disturbance and Reportable Event. The
drafting team chose not to alter this practice. Additionally this compliments all the subsections of the definition, such that there is
not a Balancing Contingency Event without a change in ACE. With regards to your comment concerning Section B the drafting
team has made a modification to add clarity. The term "responsible entity" is not in the NERC Glossary and should not be
capitalized.

Organization

Yes or No

o Based upon the above, Duke Energy suggests revising the definition to “Balancing Contingency Event: Any single event described in Subsection (A)
or (B) below, or any combination of those events occurring within less than
one minute.” Duke Energy suggests revising Subsection “A.b” to read “And,
that causes an unexpected negative change to the responsible entity’s
ACE”, and suggests revising Subsection “B” to state “Sudden loss of an
import, due to forced outage of transmission equipment that causes an
unexpected negative change to the responsible entity’s ACE.” Both changes
are suggested to clarify that this standard is applicable to the loss of
resource causing an unexpected drop in ACE. To the extent that
Subsection “C” is retained, Duke Energy suggests a similar revision to insert
the word “negative”.

o Duke Energy suggests striking Subsection “C.”, as loss of any load is
covered under the BAAL in BAL-001-2.

already implemented (curtailed) for a first contingency, and then somehow
losing the curtailment capability where the resource fully loads again
causing low ACE (second contingency)? If so, has any such event ever been
documented to warrant placing a statement subject to interpretation in the
Standard?

Question 1 Comment

No

17

The PPL NERC Registered Affiliates suggest striking the language “due to
forced outage of transmission equipment.” A responsible entity can cut a

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

PPL NERC Registered Affiliates

1. The SDT discussed this topic at length and it is not whether the loss is a single event or a series of single events, the
triggering factor is the total loss within the rolling one minute time frame.
2. The SDT has modified Section C to address concerns expressed by the industry. The term “known load” is no longer used in
the definition.
3. The definition has been revised after consideration of Duke Energy's comments.

Response: Thank-you for your comments and the SDT provides the following responses:

Organization

Yes or No

tag for reasons other than a forced outage of transmission equipment
(equipment OLs, contingency/stability/voltage criteria, etc.) - the sink BA
experiencing the loss of the import may not know the reason and thus not
know if the loss meets the definition of a Balancing Contingency Event. The
SDT replied to this comment during the Formal Comment Period, but
missed the point. The curtailment would be communicated, however, the
reason, “due to ...” would not necessarily.

Question 1 Comment

No

ACES Standards Collaborators

18

(2) We disagree with including subsection (c) in the Balancing Contingency
Event definition. Subsection (c) includes sudden “loss of a known load used
as a resource”. Loss of a load will result in positive ACE regardless of
whether it is being used a resource or not. As a result, BAL-002-2 R1 will be
duplicative with BAL-013-1 R1. Both will compel recovery of ACE from the
loss of a load. Think of it this way. If a 1000 MW load is used as a resource
to respond to a BA’s ACE that is at -100 MW, there would be 900 MW of
load remaining once the load is reduced. If that load is then lost, ACE goes
to 900 MW. Shouldn’t this be covered by the proposed BAL-013-1?

(1) We appreciate the changes that have been made to the Balancing
Contingency Event definition. It is much less complicated and more clear as
a result. However, there still has not been a justification provided for the
need of the definition. There is a statement in the background document
that the previous version of the standard was “broad and could be
interpreted in various manners”. A specific explanation how the definition
addresses the ambiguity should be provided.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

No

MISO Standards Collaborators

Response: Thank you for your comments but the SDT believes that requiring any such loss to be accompanied by "an unexpected
change to the responsible entity’s ACE" resolves your concerns. In addition, the SDT has modified the definition to provide further
clarity.

Organization

Yes or No

Question 1 Comment

No

The definition of Reportable Balancing Contingency Event includes “the
lesser of 80 percent of the MSSC or 500 MW”. We believe that the
threshold of 500 MW is too low. This is going to result in an excessive
number of “reportable” events that do not have an impact on reliability.
The retrieval and analysis of data will be burdensome and provide little
value.

No

We don't see the need for the added definition.

No

BPA recommends further clarity and explanation for the sudden unplanned
outage of a transmission facility, and sudden loss of known load used as a
resource that causes an unexpected change to responsible entity’s ACE.
BPA also recommends leaving in the failure to start language that has been
removed.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

19

The SDT has modified Section C to address concerns expressed by the industry. The term “known load” is no longer used in the

If loss of a transmission facility results in an unexpected change to ACE it meets the definition.

Response: Thank you for your comments.

Bonneville Power Administration

Response: The SDT chose to use a more specific and granular definition rather that the current definition – Disturbance which is
broad and vague and is subject to interpretation.

IRC-SRC

Response: The SDT has modified the definition to address the concerns expresses by the industry regarding the threshold. Please
refer to the Background Document for further clarification on this issue.

Oklahoma Gas & Electric

1. The SDT chose to use a more specific and granular definition rather that the current definition – Disturbance which is broad
and vague and is subject to interpretation.
2. The SDT interprets your comments as being a loss of load event which was not the intention. Section C has been modified
to clarify the intention and address concerns expressed by the industry.

Response: Thank you for your comments:

Organization

Yes or No

Question 1 Comment

No

The Background Document discusses frequency deviations on Page 4 under
“Balancing Contingency Event.” This seems to preclude any human action
to alter Net Scheduled Interchange as a “Balancing Contingency Event.”

Does this mean that there is no human action when the ACE change occurs?
Does this mean that a human action to change a Net Interchange value in
the ACE equation is “unexpected” when it is due some force majeure
condition? Clarity around this issue is necessary to prevent Balancing
Authorities (BA) from merely adjusting their Net Schedule Interchange
value to correct ACE and passing the problem on to another BA. If
transmission curtailments and unexpected adjustments to e-tags are
acceptable events to deploy contingency reserve and are considered
“Sudden Loss of Generation” under BAL-002-2, this needs to be explicitly
stated. If transmission curtailments and unexpected adjustments to e-tags
are NOT acceptable events to deploy contingency reserve and are NOT
considered “Sudden Loss of Generation” under BAL-002-2, this needs to be
explicitly stated.

The changes to the definitions add clarity, but ambiguity still exists around
one phrase. What constitutes an “unexpected change to the responsible
entity’s ACE?”

NV Energy

20

Inclusion of “Sudden loss of a known load” is at odds with the Contingency

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

No

The SDT is unsure as to the meaning of your comment concerning the Background Document and human action. Without further
clarity the SDT cannot provide a response.

Response: Thank you for your response. The SDT considers the word “unexpected” to be clear and to be accepted by the industry.

Avista

Based on the initial posting, the SDT removed “failure to start” from the definition due to the overwhelming objection from the
industry on including this within the definition.

definition.

Organization

Yes or No
Reserve definition, especially in light of the fact that loss of load cause ACE
to increase (become more positive). In other words, why would one carry
reserves to handle a decrease in load? It’s illogical. What the SDT may be
trying to reference is the use of interruptible load as a type or reserve. As
such, load should not be in the Contingency Event definition.

Question 1 Comment

No

The term "ACE" should be replaced by the term "Reportable ACE" wherever
it is used in this definition. "ACE" is not adequately defined while
"Reportable ACE" is.

No

Tacoma Power is unfamiliar with the phrase, “... known load used as a
resource ...” We believe the industry cannot interpret these words
consistently. Instead, we suggest using the phrase, “... interruptible load
claimed as available reserves ...,” which is Tacoma Power’s interpretation.

No

21

The definition is not explicitly clear about normal operating actions such as
special protection system (SPS) actions. Certain transmission events may
lead to generation rejection so the system stays stable after the fault. If we
interpret the proposed definition and use the same terminology, these
actions are planned, the change on the ACE is not unexpected, and they

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Hydro-Quebec TransEnergie

Response: Thank you for your response. The SDT has modified Section C to address concerns expressed by the industry. The term
“known load” is no longer used in the definition.

Tacoma Power

Response: Thank you for your response. The drafting team suggests that you intended to say "Reporting ACE" since "Reportable
ACE" has not been proposed as a new definition. We agree with you suggestion, that the proposed definition of "Reporting ACE"
should be included in both this standard and BAL-001-2 until it is approved and included in the Glossary.

Energy Mark, Inc.

Response: Thank you for your response. The SDT disagrees that it is trying to reference interruptible load as a type of reserve.
The SDT has modified Section C to address concerns expressed by the industry. The term “known load” is no longer used in the
definition.

Organization

Yes or No

Additionally, some single contingencies may lead to generation loss as well
as load loss after the breaker operations. For example, if 1200 MW of
generation is loss and 1000 MW of DC converters at the same time, the net
loss for the grid is 200 MW, which would be under the Reportable Balancing
Contingency Event threshold. For this reason, the Balancing Contingency
Event definition should include the notion of net loss for the grid.

could be considered as a secondary event. The generation does not
become unavailable following the trip. Consequently, these events would
not classify as Balancing Contingency Events. During the 04/02/2013
webinar, the Standard Drafting Team provided an answer in this direction.
We then understand that a CR Form 1 should not be filled for these types of
events. However, we believe that the Balancing Contingency Event
definition should be clarified to minimize the risk of misinterpretation if this
is the SDT’s intent. We suggest adding a bullet in the definition stating that
normal operating characteristics of a unit or a system such as SPS actions do
not constitute a sudden or unanticipated loss and are not subject to this
definition.

Question 1 Comment

Yes

Texas Reliability Entity

22

Definition of “Balancing Contingency Event” is slightly different in
Implementation Plan as compared to Standard (A.a.iii. Facility vs Facilities,
B. Import vs import...). Definition of “Reportable Balancing Contingency
Event “ is different in Implementation plan as compared to Standard
(Implementation Plan does not include phrase “The 80% threshold may be
reduced upon written notification to the Regional Entity.”) The Applicability
section in the Implementation Plan is also different than the Standard.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

No

MISO Standards Collaborators

Response: The SDT does not agree with your comment that the definition needs to be modified to address your concern. The
activation of a SPS may cause a contingency event on the system with the SPS or another system.

Organization

Yes or No

Question 1 Comment

Yes
Yes
Yes

Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes

Northeast Power Coodinating Council

SERC OC Standards Review 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

ERCOT

Arizona Public Service Company

Salt River Project

PacifiCorp

PJM Interconnection, LLC

EnerVision, Inc.

Tucson Electric Power

SMUD

No comment.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Yes

Manitoba Hydro

23

Response: Thanks for the catch, the Standard is correct and the implementation plan will be revised to match the Standard.

Organization

Yes

Yes
Yes
Yes
Yes
Yes
Yes

Independent Electricity System
Operator

Portland General Electric Company

ISO New England Inc.

American Electric Power

Keen Resources Ltd.

Seminole Electric Cooperative, Inc.

Xcel Energy

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Yes

Yes or No

Idaho Power Company

Organization

Question 1 Comment

24

The BARC SDT has modified the current definition for Contingency Reserve. Do you agree that the modified definition provides
for greater clarity? If not, please explain in the comment area below.

No

Yes or No

The last sentence in the definition is not needed, and should be removed. “The
capacity may be provided by resources such as Demand Side Management (DSM),
Interruptible Load and unloaded generation.” is the “How” to meet the contingency
reserve requirement, which does not belong in a definition. Suggest to remove this
sentence.

Question 2 Comment

No

The presently approved NERC definition for contingency seems adequate for this
standard. If the DCS definition will not be used any longer, recommend the team
retire it from the NERC glossary.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

25

Response: Thank you for your comments. The SDT felt it was important to update the definition to clearly state that it was for a
Balancing Contingency Event, as well as for use during EEA Levels 2 or 3, as stated in the EOP-002 Standard. The SDT included DSM
to clarify that DSM may be included as Contingency Reserve in response to the FERC directive.

MRO NERC Standards Review
Forum

Response: Thank you for your comments. The SDT included DSM to clarify that DSM may be included as Contingency Reserve in
response to the FERC directive.

Northeast Power Coodinating
Council

Organization

Many commenters question why the SDT included Demand Side Management (DSM) in the definition. The SDT stated that they
included DSM to clarify that DSM may be included as Contingency Reserve in response to the FERC directive.

Summary Consideration: The majority of negative commenters did not agree that the definition need to be modified. The SDT
explained that they felt it was important to update the definition to clearly state that it was for a Balancing
Contingency Event, as well as for use during EEA Levels 2 or 3, as stated in the EOP-002 Standard.

2.

No

Yes or No
As written there is no distinction as to whether ‘unloaded generation’ is on-line or
off-line generation. Which is it, or is it both? Additional clarification here would be
helpful.

Question 2 Comment

No

We would be in agreement except that it includes the term “Balancing Contingency
Event”, and we would need our above suggested changes made to that definition to
be in agreement here.

No

The PPL NERC Registered Affiliates believe the proposed modifications actually
introduce ambiguity and error. Attempting to provide examples (such as...) in
definitions is ill-advised as this adds ambiguity to the definition as the list may be
considered all inclusive by some and not by others. The final sentence should be
struck. As defined by NERC, Demand Side Management includes “all activities” used
to “influence” energy usage, which includes programs such as time of day rates, light
bulb replacement, and other efficiency programs which do not provide controllable
capacity. It appears the SDT may have intended to include the NERC defined term
Direct Control Load Management as an example, however, examples need not be
included in definitions.

No

26

The presently approved NERC definition for contingency seems adequate for this

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

MISO Standards Collaborators

Response: Thank-you for your comment. The SDT felt it was important to update the definition to clearly state that it was for a
Balancing Contingency Event, as well as for use during EEA Levels 2 or 3, as stated in the EOP-002 Standard. The SDT included DSM
to clarify that DSM may be included as Contingency Reserve in response to the FERC directive.

PPL NERC Registered Affiliates

Response: Thank you for your comment. The SDT believes that it addressed your concerns with the modifications that have been
made to the definition of Balancing Contingency Event.

Duke Energy

Response: Thank you for your comment. Contingency reserve can be both on-line or off-line generation provided it meets the
requirements of the particular Standard in question.

SPP Standards Review Group

Organization

Yes or No
standard.

Question 2 Comment

No

Please strike the last sentence of the definition. It is an explanation of what may
constitute contingency reserve and is not actually part of the definition. It should be
included in the background document. We understand the reason for the inclusion
may be in response to a directive to further the Commission’s policy on expanding
the use of DSM. However, the use of DSM has expanded significantly since the
directives were issued and could be said to have been “overcome” by events. It is
well understood within this industry that DSM may be used as a resource. The
drafting team could include an explanation in the application guidelines or the
background document that would explain that DSM could be used among other
resources.

No

The presently approved NERC definition for contingency reserve seems adequate for
this standard.

No

27

We generally agree with the revised definition, but do not see the need for the last
sentence: “The capacity may be provided by resources such as Demand Side
Management (DSM), Interruptible Load and unloaded generation.” This is the

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Independent Electricity
System Operator

Response: Thank you for your comment. The SDT felt it was important to update the definition to clearly state that it was for a
Balancing Contingency Event, as well as for use during EEA Levels 2 or 3, as stated in the EOP-002 Standard. The SDT included DSM
to clarify that DSM may be included as Contingency Reserve in response to the FERC directive.

IRC-SRC

Response: Thank you for your comment. The SDT felt it was important to update the definition to clearly state that it was for a
Balancing Contingency Event, as well as for use during EEA Levels 2 or 3, as stated in the EOP-002 Standard. The SDT included DSM
to clarify that DSM may be included as Contingency Reserve in response to the FERC directive.

ACES Standards Collaborators

Response: Thank you for your comment. The SDT felt it was important to update the definition to clearly state that it was for a
Balancing Contingency Event, as well as for use during EEA Levels 2 or 3, as stated in the EOP-002 Standard. The SDT included DSM
to clarify that DSM may be included as Contingency Reserve in response to the FERC directive.

Organization

Yes or No
“How’s” to meet the contingency reserve requirement, which does not belong to a
definition. We suggest to remove this sentence.

Question 2 Comment

No

Because of the nature of using hourly integrated values, Requirement R2 may not
provide Operators on shift with sufficient information in a timely manner. We
recommend an alternative that uses a timer that begins to count up when the BA
becomes deficient in contingency reserve, resulting in a compliance violation should
the condition persist for 105 minutes. Also, as proposed, it may be create
burdensome reporting requirements so that an hourly shortfall can be dismissed due
to Balancing Contingency Events, for example.

The last sentence in the definition is not needed, and should be removed. “The
capacity may be provided by resources such as Demand Side Management (DSM),
Interruptible Load and unloaded generation.” is the “How” to meet the contingency
reserve requirement, which does not belong in a definition. Suggest to remove this
sentence.

No

28

It is not clear exactly what “other contingency requirements (such as Energy
Emergency Alerts Level 2 or Level 3)” refers to.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

American Electric Power

It is not clear to the SDT how an operator that uses hourly integrated values would meet the current BAL-002 Standard in effect.
R2 is similar to the current requirement R3.1 except that it clarifies that during periods of a "Contingency Event Recovery Period
and Contingency Reserve Recovery Period, or during an Energy Emergency Alert Level 2 or 3", an entity does not need to maintain
an amount of Contingency Reserve at least equal to its Most Severe Single Contingency.

Response: Thank you for your comments. The SDT felt it was important to update the definition to clearly state that it was for a
Balancing Contingency Event, as well as for use during EEA Levels 2 or 3, as stated in the EOP-002 Standard. The SDT included DSM
to clarify that DSM may be included as Contingency Reserve in response to the FERC directive.

ISO New England Inc.

Response: Thank you for your comment. The SDT felt it was important to update the definition to clearly state that it was for a
Balancing Contingency Event, as well as for use during EEA Levels 2 or 3, as stated in the EOP-002 Standard. The SDT included DSM
to clarify that DSM may be included as Contingency Reserve in response to the FERC directive.

Organization

Yes or No

Question 2 Comment

No

The term "Contingency Reserve" defined in the current definition should be changed
to "Reserve Usable for Contingencies" which should be the term used in requirement
R2. A second, clear definition of "Contingency Reserve" should be made for use in
the Guidance Document, as reserve "allocated" for contingency/restoration, and the
term "Contingency Reserve" should thereby be made clearly usable in that
document's admonition against double counting of the three types of reserve:
Frequency Responsive, Regulating, and Contingency.

This distinction, between "usable" and "allocated" remains notoriously unclear in this
definition, and in apparent contradiction to the provision against double-counting of
reserve in the "Guidance Document" currently in preparation. To make the
distinction clear, and that occasional "double counting" of reserve types is specifically
being allowed by the BAL performance standards, this definition needs to be broken
into two definitions.

It is a definition not of reserve "allocated" to contingency/restoration, but of reserve
that is "usable" for contingency/restoration and which includes the two other defined
types of reserve, Frequency Responsive and Regulating.

The definition is left vague, to enable "double counting" of reserve types.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

29

Double counting is not allowed in the Standard. While during real time deployment of Contingency Reserve, the portfolio of
Operating Reserve may be deployed for the contingency, resulting in a potential temporary deficiency of Regulating or Frequency
Responsive reserve, the total amount of required Operating Reserve should remain the same.

The SDT does not believe that Contingency Reserve should include other types of reserve.

Response: Thank you for your comments. The SDT has discussed your comments and will leave the definition as is, except for
removing the final sentence as noted in previous responses.

Keen Resources Ltd.

Response: Thank you for your comment. Other standards, such as EOP-002-3.1 refer to deploying Operating Reserve during EEA 1
or EEA 2. This is an acknowledgement that Contingency Reserve can be deployed as a part of Operating Reserve as allowed in the
specific requirements of the various NERC Standards.

Organization

Yes or No

Yes

"The provision of capacity that may be deployed by the Balancing Authority to
respond to a Balancing Contingency Event and other contingency requirements (such
as Energy Emergency Alerts Level 2 or Level 3). The capacity may be provided by
'resources eligible under the respective BA rules, including, but not limited to,'
resources such as Demand Side Management (DSM), Interruptible Load and unloaded
generation."

ERCOT ISO suggests that the SDT consider the following changes so that the definition
of the Contingency Reserve clearly accommodates resources eligible under the
respective BA rules to provide Contingency Reserve for that BA:

Question 2 Comment

Yes

This standard is a big improvement over the existing standard because it provides
much needed formal definitions of many terms that are used but not currently
defined in BAL-002-1, the definition of Contingency Event, Contingency Reserve and
MSSC being three of them.

Yes

The Contingency Reserve definition should mention a Reserve Sharing Group in
addition to a BA.

Xcel Energy

30

If the DCS definition will not be used any longer, recommend the team retire it from
the NERC glossary.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Yes

Response: Thank you for your comment. The SDT understands your concern, but does not believe the addition of the RSG in the
definition would add to the meaning since RSGs are a grouping of BAs.

Texas Reliability Entity

Response: Thank you for your comment and support.

Salt River Project

Response: Thank you for your comment. The SDT felt it was important to update the definition to clearly state that it was for a
Balancing Contingency Event, as well as for use during EEA Levels 2 or 3, as stated in the EOP-002 Standard. The SDT included DSM to
clarify that DSM may be included as Contingency Reserve in response to the FERC directive.

ERCOT

The SDT feels that additional definitions are unnecessary.

Organization

Yes or No

Question 2 Comment

Yes

Yes
Yes

Yes
Yes

Yes

Yes

SERC OC Standards Review
Group

seattle city light

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

Oklahoma Gas & Electric

Bonneville Power
Administration

Arizona Public Service
Company

PacifiCorp

No comment.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Yes

Manitoba Hydro

31

Response: Thank you for your comment. The SDT believes that the term DCS may be used in other standards. If it is not the SDT
will look into retiring the definition.

Organization

Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes

Yes
Yes

Yes

EnerVision, Inc.

Tucson Electric Power

Avista

NV Energy

SMUD

Idaho Power Company

Energy Mark, Inc.

Portland General Electric
Company

Tacoma Power

Seminole Electric Cooperative,
Inc.

Hydro-Quebec TransEnergie

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Yes

Yes or No

PJM Interconnection, LLC

Organization

Question 2 Comment

32

The BARC SDT has created a definition for Reserve Sharing Group Reporting ACE. Do you agree with this definition? If not,
please explain in the comment area below.

No

Yes or No

There is no need to define the term Reserve Sharing Group Reporting ACE. This term
is not referenced or used in the Standard at all. If the RSG is obligated to meet the
DCS requirement and needs to return its ACE to zero or the Pre†Reportable
Contingency Event value, then the Standard is not explicit nor complete enough to
place this obligation on the RSG.

Question 3 Comment

No

Do you need to add ‘...at the time of the measurement’ at the end of the definition?

No

33

The definition should only include the BAs that were participating in the event.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

SERC OC Standards Review
Group

Response: Thank you for your comment. The SDT has made the necessary change.

SPP Standards Review Group

Response: Thank you for your comment. The use of the term Responsible Entity requires the inclusion of this definition for
Reserve Sharing Groups. The SDT eliminated Requirement R5.1 and R5.2 from the existing standard and moved the language to
this definition.

Northeast Power Coodinating
Council

Organization

Several commenters stated that the definition should only apply to BAs participating in the RSG at the time of the event. The SDT
agreed with their comment and modified the definition to state this and provide additional clarity.

Summary Consideration: Many of the commenters did not believe that it was necessary to create a definition for Reserve Sharing
Group Reporting ACE. The SDT explained that since the standard used the term Responsible Entity, it required the
inclusion of this definition for Reserve Sharing Groups. The SDT eliminated Requirement R5.1 and R5.2 from the
existing standard and moved the language to this definition.

3.

Yes or No

Question 3 Comment

No

Only BA’s participating in response to an event should be included in the Reserve
Sharing Group Reporting ACE calculation. As we commented on BAL-001-2, ACE
should be fully defined in a manner where Reporting ACE can be defined simply as
the “The scan rate values of a Balancing Authority’s ACE”.

No

The PPL NERC Registered Affiliates believe the definition should include only those
BAs participating in the specific event, not simply all BAs that are members of the
RSG. Suggest revising the definition as follows: -- Reserve Sharing Group Reporting
ACE: At any given time of measurement for the applicable Reserve Sharing Group, the
algebraic sum of the ACEs (as calculated at such time of measurement) of all of the
Balancing Authorities that are participating in the Balancing Contingency Event. --

No

This change was not proposed in the drafting team’s SAR and we see no FERC
directive to make this change. RSGs have measurement processes that have worked
well for quite some time. If the drafting team has guidance on the measurement
process, that should be put in a supporting document rather than hard-coding
additional obligations in the standard.

No

34

The definition should include only the BAs asked to participate in the reserve
recovery event.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Southern Company: Southern
Company Services, Inc.;
Alabama Power Company;

Response: Thank you for your comment. The use of the term Responsible Entity requires the inclusion of this definition for
Reserve Sharing Groups. The SDT eliminated Requirement R5.1 and R5.2 from the existing standard and moved the language to
this definition.

MISO Standards Collaborators

Response: Thank you for your comment. The SDT has modified the definition to provide clarity and address your concern.

PPL NERC Registered Affiliates

Response: Thank you for your comment. The SDT has modified the definition to provide clarity and address your concern.

Duke Energy

Response: Thank you for your comment. The SDT has modified the definition to provide clarity and address your concern.

Organization

Yes or No

Question 3 Comment

No

We believe the definition as proposed is already a common understanding and is not
needed. We simply do not see how it adds value. Further, having multiple
definitions for ACE creates confusion and is simply not needed.

No

This change was not proposed in the drafting team’s SAR and we see no FERC
directive to make this change. RSGs have measurement processes that have worked
well for quite some time. If the drafting team has guidance on the measurement
process, that should be put in a supporting document rather than hard-coding
additional obligations in the standard.

No

The definition should only include the BA’s participating in the event.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

35

Response: Thank you for your comment. The SDT has modified the definition to provide clarity and address your concern.

PJM Interconnection, LLC

Response: Thank you for your comment. The use of the term Responsible Entity requires the inclusion of this definition for
Reserve Sharing Groups. The SDT eliminated Requirement R5.1 and R5.2 from the existing standard and moved the language to
this definition.

IRC-SRC

Response: Thank you for your comment. The use of the term Responsible Entity requires the inclusion of this definition for
Reserve Sharing Groups. The SDT eliminated Requirement R5.1 and R5.2 from the existing standard and moved the language to
this definition.

ACES Standards Collaborators

Response: Thank you for your comment. The SDT has modified the definition to provide clarity and address your concern.

Georgia Power Company; Gulf
Power Company; Mississippi
Power Company; Southern
Company Generation;
Southern Company
Generation and Energy
Marketing

Organization

No

Yes or No
We do not see the need to define the term Reserve Sharing Group Reporting ACE.
This term is not referenced or used in the standard at all. On the other hand, if the
RSG is obligated to meet the DCS requirement and needs to return its ACE to zero or
the Pre†Reportable Contingency Event value, then the standard is not explicit or
complete to place this obligation on the RSG.

Question 3 Comment

No

The term "ACE" should be replaced by the term "Reportable ACE" wherever it is used
in this definition. "ACE" is not adequately defined while "Reportable ACE" is.

No

There is no need to define the term Reserve Sharing Group Reporting ACE. This term
is not referenced or used in the Standard at all. If the RSG is obligated to meet the
DCS requirement and needs to return its ACE to zero or the Pre†Reportable
Contingency Event value, then the Standard is not explicit nor complete enough to
place this obligation on the RSG.

No

36

As written, it arbitrarily precludes the calculation of an RSG ACE for an entire RSG
based upon the aggregate frequency bias, and the RSG participants' net interchange
with non-participants. The Florida Reserve Sharing Group monitors participants'

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Seminole Electric Cooperative,
Inc.

Response: Thank you for your comment. The use of the term Responsible Entity requires the inclusion of this definition for
Reserve Sharing Groups. The SDT eliminated Requirement R5.1 and R5.2 from the existing standard and moved the language to
this definition.

ISO New England Inc.

Response: Thank you for your comment. The drafting team suggests that you intended to say "Reporting ACE" since "Reportable
ACE" has not been proposed as a new definition. We agree with you suggestion, that the proposed definition of "Reporting ACE"
should be included in both this standard and BAL-001-2 until it is approved and included in the Glossary and used consistently
throughout.

Energy Mark, Inc.

Response: Thank you for your comment. The use of the term Responsible Entity requires the inclusion of this definition for
Reserve Sharing Groups. The SDT eliminated Requirement R5.1 and R5.2 from the existing standard and moved the language to
this definition.

Independent Electricity
System Operator

Organization

Yes or No
individual ACE, but calculates an RSG ACE based on the aggregate frequency biases
and net interchange with non-participants.

Question 3 Comment

No

It is in conflict with the very definiton of a balancing authority.

Yes

Note there are differing reference to Regulating Reserve Sharing Group and Reserve
Sharing Group BAL-001-2 and BAL-002-2. Seattle City Light recommends consistent
terminology across the standards.

Yes

The assumption is made that algebraic sum of the ACE’s is as follows:Reserve Sharing
Group Reporting ACE = ACE(BA1) + ACE(BA2) + ACE(BA3) + ....An example calculation
would be helpful and provide clarity.

Yes
Yes

Yes
Yes

Manitoba Hydro

MRO NERC Standards Review
Forum

Oklahoma Gas & Electric

Bonneville Power

No comment.

Same comment as for #2.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Yes

Salt River Project

37

Response: Thank you for your comment. The SDT has modified the definition to provide additional clarity as to how it is calculated.

Avista

Response: Thank you for your comment. The SDT has corrected this and is now using a single term.

seattle city light

Response: Thank you for your comment. Unfortunately, the SDT would need additional information to provide a response to your
comment.

Modesto Irrigation District

Response: Thank you for your comment. The SDT has modified the definition to provide clarity and address your concern.

Organization

Yes
Yes
Yes
Yes
Yes
Yes
Yes

Yes
Yes
Yes
Yes
Yes
Yes

PacifiCorp

EnerVision, Inc.

Tucson Electric Power

NV Energy

SMUD

Idaho Power Company

Portland General Electric
Company

American Electric Power

Tacoma Power

Texas Reliability Entity

Keen Resources Ltd.

Hydro-Quebec TransEnergie

Xcel Energy

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Yes

Yes or No

Arizona Public Service
Company

Administration

Organization

Question 3 Comment

38

The BARC SDT has added language to the proposed requirements in the standard and to the definition for Contingency Reserve
to resolve any conflicts between this standard and the EOP standards. Do you agree that this modification was necessary and
that any possible issues are now resolved? If not, please explain in the comment area.

No

Yes or No

All that’s needed is a simple statement in the applicability section that the standard
does not apply to BAs when they are in EEA 2 or 3.

Question 4 Comment

No

The PPL NERC Registered Affiliates do not agree with the proposed modifications to
the NERC defined term Contingency Reserve as explained in our comment 2.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

39

Response: Thank you for your comment. The drafting team understands your comment associated with Question No. 2, however,
the drafting team is not sure as to the meaning of your comment as it pertains to Question No. 4. The SDT felt it was important to
update the definition to clearly state that it was for a Balancing Contingency Event, as well as for use during EEA Levels 2 or 3, as

PPL NERC Registered Affiliates

Response: Thank you for your comment. The drafting team included it in both locations in order to assure no misinterpretation
by the auditors.

MRO NERC Standards Review
Forum

Organization

A few commenters felt that this standard blurred the current “clear and well-established criteria” of what triggers a DCS event. The
SDT stated that they disagreed that a “well-established criteria of what triggers the DCS event” is defined, and
attempted to provide a more specific definition. NERC definition of a Disturbance also is not clear and well defined.
What is defined is in the eye of the auditor, and the drafting team believes it has provided more granularity and
specificity.

Summary Consideration: Several commenters felt that there should only be a statement in the applicability section stating that this
standard did not apply to a BA when it was in a EEA Level 2 or 3. The SDT explained that they included it in the
applicability section and in the requirement in order to assure no misinterpretation by the auditors.

4.

No

Yes or No

It needs a simple statement in the applicability section that the standard does not
apply to BAs when they are in EEA 2 or 3.

Question 4 Comment

No

(2) It would be helpful if the drafting team explained what the conflicts with the EOP
standards are. Besides the one identified above, are there others? The background
document states that there are conflicts but does not explain them. It is difficult to
judge if the issue was addressed without an adequate explanation.

(1) We do believe that it is helpful to clarify that a BA does not have to comply with
recovering ACE and contingency reserves when it is in an EEA 2 or 3. It certainly
would not make sense to go to the extreme of shedding firm load to recover ACE or
contingency reserves if a BA was simply out of balance with no transmission security
issues, system frequency issues or stability issues. There are standards requirements
such as operating within IROLs/SOLs that would deal with these other reliability
issues and provide the indication if load needed to be shed to address the deficient
BA. A more efficient way to address this issue may be to apply the restriction in the
applicability section.

No

All that’s needed is a simple statement in the applicability section that the standard
does not apply to BAs when they are in EEA 2 or 3.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

40

Response: Thank you for your comment. The drafting team included it in both locations in order to assure no misinterpretation by

IRC-SRC

1) The drafting team included it in both locations in order to assure no misinterpretation by the auditors.
2) The drafting team will provide more explanation within the background document

Response: Thank you for your comment.

ACES Standards Collaborators

Response: Thank you for your comment. The drafting team included it in both locations in order to assure no misinterpretation by
the auditors.

MISO Standards Collaborators

stated in the EOP-002 Standard.

Organization

No

Yes or No

a. ReliabilityFirst recommends removing any references to “an Energy Emergency
Alert Level 2 or Level 3” since these are not defined terms (Energy Emergency Alert
Levels are only noted in Attachment 1, EOP-002-3). ReliabilityFirst believes the BAL002-2 should stand on its own merit and not rely on conditions within an attachment
within another standard. For example, if the Energy Emergency Alert levels
designations ever change in the future, this has the potential to have an impact on
the intent of the BAL-002-2 standard. For consideration, ReliabilityFirst recommends
defining the alert levels within the standard itself as an attachment, hence not relying
on another standard for these conditions.

Question 4 Comment

No

Please see our response to Q2 in regards to the definition of Contingency Reserve.
AEP disagrees with the second half of R1 where it begins with “or... Its
Pre†Reportable Contingency Event ACE Value, (if its Pre†Reportable Contingency
Event ACE Value was negative)...” . The language provided in this section and its subbullets are extremely confusing. It appears that the intent is to set an expectation for
recovering from multiple contingency events, however the language provided is
unnecessarily complex and will likely confuse those responsible for meeting the
requirements.

No

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

41

You mean not "possible issues" but "possible issues related to EOP standards".
Otherwise, see answer to question 2 about other issues.

Response: Thank you for your comment. The drafting team has incorporated your suggestion.

Keen Resources Ltd.

Response: Thank you for your comment. Your comments do not address the specific Question No. 4, however, the drafting team
has provided a calculator to perform the calculation and the Background Document to help resolve your conflict.

American Electric Power

Response: Thank you for your comment. The drafting team has modified the standard to provide additional clarity.

ReliabilityFirst

the auditors.

Organization

Yes

Yes or No

Yes

We agree with the change to R1 to recognize emergency operations as long as the
BAAL is implemented in BAL-001-2, as it is the only viable standard for measuring
real-time performance and the BA’s impact on Interconnection frequency during such
operation. Duke Energy agrees that the proposed language in this standard will allow
the BA to utilize its contingency reserves to continue to serve load under an Energy
Emergency Alert Level 2 or Level 3 while remaining compliant to BAL-002; however
under what circumstances, if any, should the Balancing Authority shed firm load as a
last resort to ensure that it remains compliant to Requirement R1 under normal
operations? In our opinion, the inability of a Balancing Authority to meet the 15minute DCS compliance threshold does not in itself represent a reliability issue.
There are cases in the off-peak times especially where the recovery is detrimental to
Interconnection frequency. Some of the revisions in BAL-002-2 blur the clear and
well-established criteria of what triggers the DCS event. Too much is left up to afterthe fact compliance scrutiny, and operators need unquestionable guidance on this
matter. Also, in the definition of Contingency Reserve, add the word “NERC” before
the word “contingency” for clarity.

This standard is an improvement over the existing BAL-002 because it clarifies the
requirements for a Balancing Authority or Reserve Sharing Group regarding
Contingency Reserve requirements during Energy Emergency Alerts.

Question 4 Comment

Yes

42

R2- Disturbance Recovery Period is not defined and should be changed to
Contingency Event Recovery Period.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Texas Reliability Entity

Response: Thank you for your comment. The drafting team does not agree that a “well-established criteria of what triggers the
DCS event” is defined, and attempted to provide a more specific definition. NERC definition of a Disturbance also is not clear and
well defined. The drafting team believes it has provided more granularity and specificity.

Duke Energy

Response: Thank you for your comment.

seattle city light

Organization

Yes or No

Question 4 Comment

Yes

Yes

Yes
Yes

Yes

Yes
Yes

Northeast Power Coodinating
Council

SPP Standards Review Group

SERC OC Standards Review
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

ERCOT

Oklahoma Gas & Electric

No comment.

43

This language clarifies that when in an Energy Alert 2 or 3, the BA is using all available
reserves to maintain ACE.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Yes

Manitoba Hydro

Response: Thank you for your comment.

Avista

Response: Thank you for your comment. The drafting team has made the necessary corrections to address your concern.

Organization

Yes

Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes

Yes
Yes

Yes
Yes

Arizona Public Service
Company

Salt River Project

PacifiCorp

EnerVision, Inc.

Tucson Electric Power

NV Energy

SMUD

Idaho Power Company

Independent Electricity
System Operator

Energy Mark, Inc.

Portland General Electric
Company

ISO New England Inc.

Tacoma Power

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Yes

Yes or No

Bonneville Power
Administration

Organization

Question 4 Comment

44

Yes

Hydro-Quebec TransEnergie

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Yes

Yes or No

Seminole Electric Cooperative,
Inc.

Organization

Question 4 Comment

45

The BARC SDT has developed Requirement R2 which requires entities to have Contingency Reserve at least equal to its MSSC.
This requirement was added to address, in conjunction with Requirement R1, the FERC Directive for a continent wide
Contingency Reserve policy. Do you agree that this addresses the FERC Directive? If not, please explain in the comment area.

A couple of commenters asked the SDT to develop a reserve policy. The SDT stated that they were developing a Operating Reserve
Guideline to be presented to the NERC OC for acceptance at their September 2013 meeting.

Some commenters believed that there was a embedded expectation to recover from and measure multi-contingent events beyond
MSSC. The SDT explained that they believed that Requirement R1 as written requires deployment of Contingency
Reserve up to MSSC, however, the responsible entity must meet all of the other NERC Reliability Standards to meet its
reliability obligation which may involve the deployment of Regulating or frequency responsive reserves.

A few of the commenters believed that the standard was a commodity standard and was not performance based. The SDT stated
that they had modified the existing standard by eliminating administrative requirements, however, they have
maintained requirements associated with performance and addressed the FERC directive in order 693.

Several commenters stated that the old Policy 1 noted many reasons for operating reserves and that a BA may be reluctant to deploy
its reserves since it could start the clock on the available hours. The SDT explained that they agreed that Policy 1 had
many reasons for operating reserve. BAL-002 addresses the reason for Contingency Reserve to be used during a
Balancing Contingency Event. If a BA elects to use its Contingency Reserve for other purposes it does trigger the clock
ticking on the available hours. Additionally R2 is necessary to fulfill the directive from FERC Order 693 to establish a
continent wide Contingency Reserve policy.

Summary Consideration: Many commenters felt that BAs may withhold their Contingency Reserve from events other than
reportable events so that they always have the necessary reserve obligation. The SDT stated that the present standard
requires a responsible entity to hold contingency reserve at least equal to its most severe single contingency. While
the recommended change by the SDT does not change the amount of Contingency Reserve being held, it does require
the amount to be monitored at all times. The SDT believes the 99.77% performance expectation per calendar quarter
(averaged over each clock hour) provides the responsible entity a reasonable period of flexibility.

5.

No

Yes or No

Question 5 Comment

47

We believe the way a way to achieve the Commissions directive for a continent wide

This proposal sets a commodity standard which is not in keeping with the superior
approach of having performance-based standards. Not all BAs have the same needs
for the various types of operating reserves. Performance is the demonstration of
adequacy. Is the SDT stating that recovery is needed to recover to zero or MSSC?

The last most significant unintended consequence relates to the embedded
expectation to recover from and measure multi-contingent events beyond MSSC.
When these events happen, something bigger is going on. Transmission security is
probably an issue. Forcing a knee-jerk expectation to drive ACE back toward zero
during a major event will likely do more harm than good. This is another thing that
wasn’t in the drafting team’s SAR or in a directive. Events greater than MSSC should
be reported, but not evaluated for compliance. While it’s fine to embed some of the
calculations in the background document in a reporting form, events greater than
MSSC should be excluded from compliance evaluation.

The second unintended consequence for those BAs that don’t withhold contingency
reserves for non-DCS events is that they will be obliged to increase the amount of
contingencies the carry so they always have more reserves than their MSSC. This will
increase costs to our customers without a demonstrated need. DCS performance in
North America has been stellar compared to what was considered adequate
performance under Policy 1. Please clarify.

The original Policy 1 noted many reasons for operating reserves. BAs whose ACE is
extremely negative for other reasons would be reluctant to deploy their contingency
reserves because the timer would start ticking on the “available hours” clock Please
clarify.

This requirement will have significant negative unintended consequences. Reserves
are an inventory intended to be used when there is a reliability need. The first
unintended consequence is that BAs are encouraged by this requirement never to
deploy their contingency reserves except for a DCS-reportable events.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

MRO NERC Standards Review
Forum

Organization

Yes or No

The policy should provide simple definitions for frequency responsive, regulating,
contingency, and replacement reserves. Once the policy has undergone comment
through the standards process (this was the directive in 693), NERC should add these
four types of reserves to “Attachment 1-TOP-005 Electric System Reliability Data”
with the expectation in the policy that Reliability Coordinators collect this
information in real time for use in the EEA process.

policy is for the drafting team, in concert with the NERC operating committee, to
create a policy document that outlines the factors that the BA uses in performing an
assessment of needed frequency responsive, regulating and contingency reserves.

Question 5 Comment

No

48

This requirement will have significant negative unintended consequences. Reserves
are an inventory intended to be used when there is a reliability need.The first

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

SERC OC Standards Review
Group

[5] The SDT is drafting a Reserve Policy Guideline for consideration by the NERC Operating Committee.

[4] The SDT modified the existing standard by eliminating administrative requirements, however, they have maintained
requirements associated with performance and addressed the FERC directive in order 693

[3] The SDT believes that Requirement R1 as written requires deployment of Contingency Reserve up to MSSC, however, the
responsible entity must meet all of the other NERC Reliability Standards to meet its reliability obligation which may involve the
deployment of Regulating or frequency responsive reserves.

[2] The present standard requires a responsible entity to hold contingency reserve at least equal to its most severe single
contingency. While the recommended change by the SDT does not change the amount of Contingency Reserve being held it does
require the amount to be monitored at all times. The SDT believes the 99.77% performance expectation per calendar quarter
(averaged over each clock hour) provides the responsible entity a reasonable period of flexibility.

[1] The SDT agrees with your statement that Policy 1 had many reasons for operating reserve. BAL-002 addresses the reason for
Contingency Reserve to be used during a Balancing Contingency Event. If a BA elects to use its Contingency Reserve for other
purposes it does trigger the clock ticking on the available hours. Additionally R2 is necessary to fulfill the directive from FERC
Order 693 to establish a continent wide Contingency Reserve policy.

Response: Thank you for your comment.

Organization

Organization

Question 5 Comment

49

We agree with the principle of a BA maintaining contingency reserves to respond to
its MSSC. However, as R2 is currently proposed it puts the BA at risk if contingency
reserves fall below its MSSC for any single sampling period. Indeed, as stated it puts a
BA with a 2 second sampling interval at greater risk than a BA with a 6 second
sampling interval. While the SDT has attempted to resolve this issue in the Measures
and VSL, we believe that the requirement needs to stand on its own and that the

The policy should provide simple definitions for frequency responsive, regulating,
contingency, and replacement reserves. Once the policy has undergone comment
through the standards process (this was the directive in 693), NERC should add these
four types of reserves to “Attachment 1-TOP-005 Electric System Reliability Data”
with the expectation in the policy that Reliability Coordinators collect this
information in real time for use in the EEA process.

We believe a way to achieve the Commissions directive for a continent wide policy is
for the drafting team, in concert with the NERC operating committee, to create a
policy document that outlines the factors that the BA uses in performing an
assessment of needed frequency responsive, regulating and contingency reserves.

This will increase costs to our customers without a demonstrated need. DCS
performance in North America has been stellar compared to what was considered
adequate performance under Policy 1. Not all BAs have the same needs for the
various types of operating reserves. Performance is the demonstration of adequacy.

The second unintended consequence for those BAs that don’t withhold contingency
reserves for non-DCS events is that they will be obliged to increase the amount of
contingency reserves they carry so they always have more reserves than their MSSC.

The original Policy 1 noted many reasons for operating reserves. BAs whose ACE is
extremely negative for other reasons would be reluctant to deploy their contingency
reserves because the timer would start ticking on the “available hours” clock.

unintended consequence is that BAs are encouraged by this requirement never to
deploy their contingency reserves except for DCS-reportable events.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Yes or No

Yes or No
specifying language should be included in R2 itself.

Question 5 Comment

No

50

Seattle City Light finds Requirement R2 and Measure M2 to lack specificity as to what
level of performance is required for compliance, and recommends the following
changes:”R2. Each Responsible Entity shall maintain an amount of Contingency
Reserve such that its clock-minute average of Contingency Reserves is equal or
greater than the Most Severe Single Contingency except during the Disturbance
Recovery Period and Contingency Reserve Recovery Period, or during an Energy
Emergency Alert 2 or 3.””M2. Each Balancing Authority shall provide evidence, upon
request, such as dated calculation output from spreadsheets, Energy Management
System logs, software programs, or other evidence (either hard copy or electronic
format) to demonstrate compliance with Requirement R2.”

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

seattle city light

[5] The SDT is drafting a Reserve Policy Guideline for consideration by the NERC Operating Committee.

[4] The SDT modified the existing standard by eliminating administrative requirements, however, they have maintained
requirements associated with performance and addressed the FERC directive in order 693

[3] The SDT believes that Requirement R1 as written requires deployment of Contingency Reserve up to MSSC, however, the
responsible entity must meet all of the other NERC Reliability Standards to meet its reliability obligation which may involve the
deployment of Regulating or frequency responsive reserves.

[2] The present standard requires a responsible entity to hold contingency reserve at least equal to its most severe single
contingency. While the recommended change by the SDT does not change the amount of Contingency Reserve being held it does
require the amount to be monitored at all times. The SDT believes the 99.77% performance expectation per calendar quarter
(averaged over each clock hour) provides the responsible entity a reasonable period of flexibility.

[1] The SDT agrees with your statement that Policy 1 had many reasons for operating reserve. BAL-002 addresses the reason for
Contingency Reserve to be used during a Balancing Contingency Event. If a BA elects to use its Contingency Reserve for other
purposes it does trigger the clock ticking on the available hours. Additionally R2 is necessary to fulfill the directive from FERC
Order 693 to establish a continent wide Contingency Reserve policy.

Response: Thank you for your comment.

Organization

Yes or No

Question 5 Comment

Duke Energy

51

Duke Energy would suggest modifying Measure M2 to read at the end “except during

Language in Requirement R2 should also recognize that Contingency Reserves may be
used from time to time to aid in balancing aside from the loss of resource - today
such use takes places and does not impact compliance under DCS.Measure M2
requires that the Contingency Reserve averaged over each clock hour is greater than
or equal to the amounts identified in Requirement 2 - however, as the amounts
identified in Requirement R2 are allowed to be less than MSSC, it is not clear why the
language at the end places an exception only on the 105-minute combined recovery
and restoration period, and not on any period such resources may be utilized under
an EEA2 or EEA3.

Duke Energy would suggest the following change: “Except during the Contingency
Event Recovery Period and Contingency Reserve Restoration Period, or during an
Energy Emergency Alert Level 2 or Level 3, each Responsible Entity shall maintain an
hourly average amount of Contingency Reserve at least equal to its Most Severe
Single Contingency.”

Requirement 2 refers to “Disturbance Recovery Period” and “Contingency Reserve
Recovery Period” which are no longer defined.

Requirement R1 and R2 could provide a consistent continent-wide Contingency
Reserve policy if the definition of Balancing Contingency Event provided a “bright
line” to the industry on what events would be applicable to the determination of
MSSC; we believe that Subsection “C.” of that definition should be deleted, per our
comment under question #1 above, and if the R2 allowed for other use of
Contingency Reserves.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

No

Response: Thank you for your comment. The present standard requires a responsible entity to hold contingency reserve at least
equal to its most severe single contingency. While the recommended change by the SDT does not change the amount of
Contingency Reserve being held, it does require the amount to be monitored at all times. The SDT believes the 99.77%
performance expectation per calendar quarter (averaged over each clock hour) provides the responsible entity a reasonable
period of flexibility.

Organization

Yes or No

Though suggestions have been provided, Duke Energy does not support the adoption
of Requirement R2 and agrees with the comments provided by MISO. Performance
under the existing BAL-002 has been stellar without the need for an additional
requirement to track Contingency Reserves to the extent prescribed. The current
DCS is a very effective results-based standard. The existence of a requirement such
as R2 will result in inefficient utilization of resources, increased costs, inaccurate
representation of resource capability, and other negative consequences with no
benefit to reliability.

Also, we believe the Standard Drafting Team should carefully check to make certain
that these new definitions don’t impact other existing definitions.

Though an hourly average is proposed, it is not practical for a BA to track its
Contingency Reserves in a manner where it would make the choice to increase its
Contingency Reserves above the MSSC if it happened to drop below its MSSC for
some time in the same hour - it is an unnecessary activity to bring into real-time
operations.

an Energy Emergency Alert Level 2 or Level 3, or within the first 105 minutes
following an event requiring the activation of Contingency Reserve.”

Question 5 Comment

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

52

[4] The SDT disagrees with your comment. The exception does cover EEA Levels 2 and 3. However, the SDT has modified the
standard to provide additional clarity.

[3] The present standard requires a responsible entity to hold contingency reserve at least equal to its most severe single
contingency. While the recommended change by the SDT does not change the amount of Contingency Reserve being held, it does
require the amount to be monitored at all times. The SDT believes the 99.77% performance expectation per calendar quarter
(averaged over each clock hour) provides the responsible entity a reasonable period of flexibility.

[2] The SDT has made the necessary correction.

[1] The SDT has made further modifications to the definition and believes that these modifications provide sufficient clarity.

Response: Thank you for your comment.

Organization

Yes or No

Question 5 Comment

No

PPL NERC Registered Affiliates do not agree that the development of additional
requirements is necessary to meet the FERC directive for a continent wide policy.
Additional comments on this topic provided under question 10.

No

53

The second unintended consequence for those BAs that don’t withhold contingency
reserves for non-DCS events is that they will be obliged to increase the amount of
contingencies the carry so they always have more reserves than their MSSC. This will
increase costs to our customers without a demonstrated need. DCS performance in
North America has been stellar compared to what was considered adequate

R2 has nothing to do with a Continent Wide Contingency Reserve Policy and there is
nothing in the drafting team’s SAR that calls for the implementation of a commodity
standard. This requirement will have significant negative unintended consequences.
Reserves are an inventory intended to be used when there is a reliability need. The
first unintended consequence is that BAs are encouraged by this requirement never
to deploy their contingency reserves except for a DCS-reportable events. The original
Policy 1 noted many reasons for operating reserves. BAs whose ACE is extremely
negative for other reasons would be reluctant to deploy their contingency reserves
because the timer would start ticking on the “available hours” clock.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

MISO Standards Collaborators

The SDT has decreased the number of requirements and provided additional clarity. The essence of the proposed R1 and R2 still
encompass the intent of the current BAL-002.

Response: Thank you for your comment.

PPL NERC Registered Affiliates

[8] We believe that the proposed standard clarifies the intent of the current standard.

[7] The SDT has checked and believes there are no conflicts.

[6] The SDT believes that this calculation can be easily accomplished in most standard EMS. The value provided to the System
Operator through heightened situational awareness is worth the effort.

[5] The SDT has modified the requirement and measure and believes that the modifications provide the necessary clarity.

Organization

Organization

Question 5 Comment

54

What type of proof of deliverability is required? Some of the background information
implies that frequency responsive resources must be removed from the Contingency
Reserve calculation. How much? All headroom? Enough to provide the IFRO?This
proposal sets a commodity standard which is not in keeping with the superior
approach of having performance-based standards. Not all BAs have the same needs
for the various types of operating reserves. Performance is the ultimate
demonstration of adequacy.We believe the way a way to achieve the Commissions
directive for a continent wide “contingency reserve” policy is for the drafting team, in
concert with the NERC operating committee, to create a policy document that
outlines the factors that the BA uses in performing an assessment of needed
frequency responsive, regulating and contingency reserves. The document the
drafting team is working on is a good start. The policy should provide simple
definitions for frequency responsive, regulating, contingency, and replacement

A fundamental flaw in R2 is that drafting team has implemented a commodity
expectation that the BA must have contingency reserves above MSSC at all times and
yet has provided no clear definition on how this is measured (does it include all
generation headroom available in 10 minutes? In 15 minutes? What about resources
that are also providing AGC? Does their instantaneous headroom count? Are load
resources available in 15 minutes or 10 minutes counted?

The last most significant unintended consequence relates to the embedded
expectation to recover from and measure multi-contingent events beyond MSSC.
When these events happen, something bigger is going on. Transmission security is
probably an issue. Forcing a knee-jerk expectation to drive ACE back toward zero
during a major event will likely do more harm than good. This is another thing that
wasn’t in the drafting team’s SAR nor in a directive. Events greater than MSSC should
be reported, but not evaluated for compliance. While it’s fine to embed some of the
calculations in the background document in a reporting form, events greater than
MSSC should be excluded from compliance evaluation.

performance under Policy 1.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Yes or No

Yes or No

Once the policy has undergone comment through the standards process (this was the
directive in 693), NERC should add these four types of reserves to “Attachment 1TOP-005 Electric System Reliability Data” with the expectation in the policy that
Reliability Coordinators collect this information in real time for use in the EEA
process.

reserves.

Question 5 Comment

No

55

The proposed requirement would have significant negative consequences as
Reserves are an inventory intended to be used when there is a reliability need.A BA
could be encouraged to never deploy their CRs except for during a DCS-reportable
event. The original Policy 1 noted many reasons for operating reserves. BAs whose
ACE is extremely negative for other reasons would be reluctant to deploy their
contingency reserves because the time would start ticking on the ‘available hours’

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Southern Company: Southern
Company Services, Inc.;
Alabama Power Company;
Georgia Power Company; Gulf
Power Company; Mississippi
Power Company; Southern

[6] The SDT believes that this is outside the scope of the current SAR.

[5] The SDT is developing a proposed Reserve Policy Guideline for the NERC OC consideration by the NERC OC.

[4] The SDT does not believe that they have excluded anything that is in the present standard with regards to what would count
as contingency reserve but has in actuality provided clarity to the present wording in the current BAL-002.

[3] The SDT believes that Requirement R1 as written requires deployment of Contingency Reserve up to MSSC, however, the
responsible entity must meet all of the other NERC Reliability Standards to meet its reliability obligation which may involve the
deployment of Regulating or frequency responsive reserves.

[2] The present standard requires a responsible entity to hold contingency reserve at least equal to its most severe single
contingency. While the recommended change by the SDT does not change the amount of Contingency Reserve being held, it does
require the amount to be monitored at all times. The SDT believes the 99.77% performance expectation per calendar quarter
(averaged over each clock hour) provides the responsible entity a reasonable period of flexibility.

[1] The SDT has modified the existing standard by eliminating administrative requirements. However, they have maintained
requirements associated with performance and addressed the FERC directive in order 693.

Response: Thank you for your comment.

Organization

Yes or No

While we agree with the principle of a BA maintaining Contingency Reserves to
respond to its MSSC, the proposed R2 puts the BA at risk if CR reserves fall below its
MSSC for any single sampling period. For example, BAs with a 2 second sampling
interval would be at greater risk than a BA with a 6 second sampling interval. While
the SDT has attempted to resolve this issue in the proposed Measures and VSLs, we
suggest that specific language be included in R2 and not just in the Measure (SERC
OC). A reference to the integrated clock hour should be included in R2 as in the
Measure.

Once the policy has undergone comment through the standard’s process, we suggest
that NERC add these four types of reserves to ‘Attachment 1-TOP-005 Electric System
Reliability data” with the noted expectation that RCs collect this information in real
time for use in the EEA process.

We suggest the SDT work with the NERC OC to create a policy document that outlines
the factors the BA uses in performing an assessment of needed frequency
responsive, regulating and contingency reserves and provide simple definitions for
frequency responsive, regulating, contingency, and replacement reserves.

Additionally, BAs that don’t withhold CRs for non-DCS events might feel the need to
increase the amount of contingencies they carry in order to always have more
reserves than their MSSC which in turn, would increase customer costs without a
demonstrated need. We suggest that not all BAs have the same needs for the various
types of operating reserves and that performance is the demonstration of adequacy.

clock.

Question 5 Comment

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

56

[1] The SDT agrees with your statement that Policy 1 had many reasons for operating reserve. BAL-002 addresses the reason for
Contingency Reserve to be used during a Balancing Contingency Event. If a BA elects to use its Contingency Reserve for other
purposes it does trigger the clock ticking on the available hours. Additionally R2 is necessary to fulfill the directive from FERC
Order 693 to establish a continent wide Contingency Reserve policy.

Response: Thank you for your comment.

Company Generation;
Southern Company
Generation and Energy
Marketing

Organization

Yes or No

Question 5 Comment

No

57

Since the FERC directive that is driving this requirement is to establish a continent
wide policy on contingency reserve, a better solution would be for NERC to write an
operating policy describing appropriate uses of various types of contingency reserves.
A guideline document would provide better details for an operating policy than a
requirement.

(2) While contingency reserve is just one type of operating reserve and is intended
for use to respond to contingent events, a BA should not be restricted to deploying it
only for contingent events. There may be other reasons for a BA to have a large
negative ACE (i.e. units don’t ramp as expected) and the BA should be free to call
upon its contingency reserve to recover ACE in such a situation.

(1) We are concerned that this requirement will have unintended consequences. As
written, a BA will be forced to only deploy contingency reserve for responding to
resource contingencies. Consequently, the BA will have to carry more operating
reserves which increases their operating costs tremendously without commensurate
reliability benefit. Furthermore, there is no data indicating that operating reserves
carried by BAs today are insufficient.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Response: Thank you for your comment.

ACES Standards Collaborators

[5] The present standard requires a responsible entity to hold contingency reserve at least equal to its most severe single
contingency. While the recommended change by the SDT does not change the amount of Contingency Reserve being held it does
require the amount to be monitored at all times. The SDT believes the 99.77% performance expectation per calendar quarter
(averaged over each clock hour) provides the responsible entity a reasonable period of flexibility.

[4] The SDT believes that this is outside the scope of the current SAR.

[3] The SDT is developing a proposed Reserve Policy Guideline for the NERC OC consideration by the NERC OC.

[2] The SDT believes that Requirement R1 as written requires deployment of Contingency Reserve up to MSSC, however, the
responsible entity must meet all of the other NERC Reliability Standards to meet its reliability obligation which may involve the
deployment of Regulating or frequency responsive reserves.

Organization

Yes or No

Question 5 Comment

IRC-SRC

58

The last significant unintended consequence relates to the embedded expectation to
recover from and measure multi-contingent events beyond MSSC. When these
events happen, something bigger is going on. Transmission security is probably an
issue. Forcing a knee-jerk expectation to drive ACE back toward zero during a major
event will likely do more harm than good. This is another thing that wasn’t in the
drafting team’s SAR or in a directive. Events greater than MSSC should be reported,

The second unintended consequence for those BAs that don’t withhold contingency
reserves for non-DCS events is that they will be obliged to increase the amount of
contingencies the carry so they always have more reserves than their MSSC. This will
increase costs to our customers without a demonstrated need. DCS performance in
North America has been stellar compared to what was considered adequate
performance under Policy 1.

The original Policy 1 noted many reasons for operating reserves. BAs whose ACE is
extremely negative for other reasons would be reluctant to deploy their contingency
reserves because the timer would start ticking on the “available hours” clock.

We believe this requirement will have significant negative unintended consequences.
Reserves are an inventory intended to be used when there is a reliability need. The
first unintended consequence is that BAs are encouraged by this requirement never
to deploy their contingency reserves except for a DCS-reportable events.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

No

[3] The SDT is developing a proposed Reserve Policy Guideline for the NERC OC consideration by the NERC OC.

[2] The SDT agrees with your statement that Policy 1 had many reasons for operating reserve. BAL-002 addresses the reason for
Contingency Reserve to be used during a Balancing Contingency Event. If a BA elects to use its Contingency Reserve for other
purposes it does trigger the clock ticking on the available hours. Additionally R2 is necessary to fulfill the directive from FERC
Order 693 to establish a continent wide Contingency Reserve policy.

[1] The present standard requires a responsible entity to hold contingency reserve at least equal to its most severe single
contingency. While the recommended change by the SDT does not change the amount of Contingency Reserve being held, it does
require the amount to be monitored at all times. The SDT believes the 99.77% performance expectation per calendar quarter
(averaged over each clock hour) provides the responsible entity a reasonable period of flexibility.

Organization

Yes or No

Once the policy has undergone comment through the standards process (this was the
directive in 693), NERC should add these four types of reserves to “Attachment 1TOP-005 Electric System Reliability Data” with the expectation in the policy that
Reliability Coordinators collect this information in real time for use in the EEA
process.

We believe the way a way to achieve the Commission’s directive for a continent wide
policy is for the drafting team, in concert with the NERC operating committee, to
create a policy document that outlines the factors that the BA uses in performing an
assessment of needed frequency responsive, regulating and contingency reserves.
The policy should provide simple definitions for frequency responsive, regulating,
contingency, and replacement reserves.

This proposal sets a commodity standard which is not in keeping with the superior
approach of having performance-based standards. Not all BAs have the same needs
for the various types of operating reserves. Performance is the demonstration of
adequacy.

but not evaluated for compliance. While it’s fine to embed some of the calculations
in the background document in a reporting form, events greater than MSSC should
be excluded from compliance evaluation.

Question 5 Comment

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

59

[2] The present standard requires a responsible entity to hold contingency reserve at least equal to its most severe single
contingency. While the recommended change by the SDT does not change the amount of Contingency Reserve being held, it does
require the amount to be monitored at all times. The SDT believes the 99.77% performance expectation per calendar quarter
(averaged over each clock hour) provides the responsible entity a reasonable period of flexibility.

1] The SDT agrees with your statement that Policy 1 had many reasons for operating reserve. BAL-002 addresses the reason for
Contingency Reserve to be used during a Balancing Contingency Event. If a BA elects to use its Contingency Reserve for other
purposes it does trigger the clock ticking on the available hours. Additionally R2 is necessary to fulfill the directive from FERC
Order 693 to establish a continent wide Contingency Reserve policy.

Response: Thank you for your comment.

Organization

Yes or No

Question 5 Comment

No

60

DCS performance in North America has been greatly improved compared to what was
considered adequate performance under Policy 1. Not all BAs have the same needs
for the various types of operating reserves. Performance is the demonstration of

Even if PJM agreed with the proposed R2, which we do not, as written it puts the BA
at risk if contingency reserves fall below its MSSC for any single sampling period.
Indeed, as stated it puts a BA with a 2 second sampling interval at greater risk than a
BA with a 6 second sampling interval. While the SDT has attempted to resolve this
issue in the Measures, specifically M2, PJM believes that the requirement needs to
stand on its own and that the specifying language should be included in R2 itself.

PJM agrees with the principle of a BA maintaining contingency reserves to respond to
its MSSC but believe this requirement would have negative unintended
consequences. Reserves should be used when there is a reliability need that may or
may not be caused by the loss of a resource. This requirement encourages BA’s to
withhold deployment of contingency reserves except for DCS reportable
disturbances. For example, if a BA’s ACE is dragging into the top of the hour, along
with Interconnection frequency, due to schedule changes and slow unit response,
this requirement incentivizes the BA to withhold deploying reserves. If a BA is
approaching an IROL that could be mitigated by deploying contingency reserves, this
requirement penalizes the BA for doing so, even though the result would benefit the
Interconnection.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

PJM Interconnection, LLC

[5] The SDT is drafting a Reserve Policy Guideline for consideration by the NERC Operating Committee.

[4] The SDT modified the existing standard by eliminating administrative requirements, however, they have maintained
requirements associated with performance and addressed the FERC directive in order 693

[3] The SDT believes that Requirement R1 as written requires deployment of Contingency Reserve up to MSSC, however, the
responsible entity must meet all of the other NERC Reliability Standards to meet its reliability obligation which may involve the
deployment of Regulating or frequency responsive reserves.

Organization

Yes or No

Once the policy has undergone comment through the standards process, as was a
directive in 693), NERC could add these four types of reserves to “Attachment 1-TOP005 Electric System Reliability Data”.

We believe a way to achieve the Commission’s directive for a continent wide policy is
for the drafting team, in concert with the NERC operating committee, to create a
policy document that outlines the factors that the BA uses in performing an
assessment of needed frequency responsive, regulating and contingency reserves.
The policy should provide simple definitions for frequency responsive, regulating,
contingency, and replacement reserves.

adequacy.

Question 5 Comment

No

61

Please consider revising requirement R2 to use the proposed new definitions as
follows:R2. Except during the Contingency Event Recovery Period and Contingency
Reserve Restoration Period, or during an Energy Emergency Alert Level 2 or 3, each

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Alberta Electric System
Operator

[5] The SDT believes that this is outside the scope of the current SAR.

[4] The SDT is developing a proposed Reserve Policy Guideline for the NERC OC consideration by the NERC OC.

[3] The SDT cannot agree or disagree with your comment concerning DCS performance, but does agree that not all BAs have the
same needs.

[2] The present standard requires a responsible entity to hold contingency reserve at least equal to its most severe single
contingency. While the recommended change by the SDT does not change the amount of Contingency Reserve being held, it does
require the amount to be monitored at all times. The SDT believes the 99.77% performance expectation per calendar quarter
(averaged over each clock hour) provides the responsible entity a reasonable period of flexibility.

[1] The SDT agrees with your statement that Policy 1 had many reasons for operating reserve. BAL-002 addresses the reason for
Contingency Reserve to be used during a Balancing Contingency Event. If a BA elects to use its Contingency Reserve for other
purposes it does trigger the clock ticking on the available hours. Additionally R2 is necessary to fulfill the directive from FERC
Order 693 to establish a continent wide Contingency Reserve policy.

Response: Thank you for your comment.

Organization

Yes or No

Responsible Entity shall maintain an amount of Contingency Reserve at least equal to
its Most Severe Single Contingency. [Violation Risk Factor: Medium] [Time Horizon:
Real†time Operations]

Question 5 Comment

No

I believe that this requirement falls under Paragraph 81 and should not be in the
standard.

No

62

The FERC Directive then sought to expand the definition of Contingency Reserve to
include demand-side resources, and to set the requirement of a quantity of
"Contingency Reserve", without specifying "Contingency Reserve" as any particular
reserve type. So, yes, R2 does address the FERC Directive, but the FERC Directive is
itself inadequate for failing to make the all-important distinction between type of
reserve, and usability of different reserve types to meet a single reliability objective
which would be some generalized "Responding" to a "Contingency" without
specifying the "type" of response which distinguishes reserve types. Rather than
simply "address" a technically uninformed FERC Directive, NERC should in its superior

As explained in my Comment to Question 2, the commonly used term "Contingency
Reserve" needs to be unpacked into two terms: "Contingency Reserve" (to be used in
the "Guidance Document" currently being prepared) and "Reserve Usable for
Contingencies" (to be used in this standard instead of "Contingency Reserve"). The
FERC Directive 693 did not identify and sort out this ambiguity and called simply for a
requirement of undifferentiated "response" to a contingency, without distinguishing
between the three intrinsic "types" of response, namely Frequency Response,
Regulating Response, and Contingency Response, except to designate the
"objective"/cause of the Response. All three types of response can meet that
objective.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Keen Resources Ltd.

Response: Thank you for your comment. The SDT modified the existing standard by eliminating administrative requirements,
however, they have maintained requirements associated with performance and addressed the FERC directive in order 693.

Energy Mark, Inc.

Response: Thank you for your comment. The SDT has made the necessary corrections.

Organization

Yes or No

reliability wisdom/competence seek to improve upon the FERC Directive and
establish the precedent that FERC takes technical direction from NERC, not the other
way around and without opposing or contradicting FERC.

Question 5 Comment

No

This standard ahs been and should continue to be results based. R2 imposes a
tracking and evidentiary requirement which is unreasonable and is not warranted by
past performance and results. If the logical next step to be standards proscribing the
measurement, qualification, etc. for contingency reserves?

Yes

A Responsible Entity may have an internal Contingency Reserve policy that is
different than the proposed language in R2. While we understand the R2 states the
minimum Contingency Reserve amount, should R2 be re-worded to state that each
Responsible Entity shall maintain an amount of Contingency Reserve as least equal to
its Most Severe Single Contingency or an amount per its Contingency Reserve policy,
whichever is larger? Ex. The MSSC in ERCOT is 1375 MW, but the required minimum
responsive reserve is 2300 MW, which is the amount necessary to maintain adequate
primary frequency response to meet the intent of the BAL-003 standard.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

63

Response: Thank you for your comment. The SDT is only requiring a minimum amount of Contingency Reserve to be available.
There is nothing in the standard to preclude an entity to carry additional Contingency Reserve.

Texas Reliability Entity

Response: Thank you for your comment. The SDT modified the existing standard by eliminating administrative requirements,
however, they have maintained requirements associated with performance and addressed the FERC directive in order 693.

Seminole Electric Cooperative,
Inc.

The SDT is developing a Reserve Policy Guideline for consideration by the NERC OC that will address the concern you have
identified in a different manner.

The SDT has reviewed your suggested modification to the definitions, but feel that the current definitions, as presently modified,
provide for sufficient clarity.

Response: Thank you for your comment.

Organization

Yes

Yes
Yes
Yes
Yes

Yes

Yes
Yes
Yes
Yes
Yes
Yes
Yes

Northeast Power Coodinating
Council

SPP Standards Review Group

ERCOT

Oklahoma Gas & Electric

Bonneville Power
Administration

Arizona Public Service
Company

Salt River Project

PacifiCorp

EnerVision, Inc.

Tucson Electric Power

Avista

NV Energy

SMUD

No comment.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Yes

Yes or No

Manitoba Hydro

Organization

Question 5 Comment

64

Yes

Yes

Yes
Yes
Yes
Yes
Yes

Independent Electricity
System Operator

Portland General Electric
Company

ISO New England Inc.

American Electric Power

Tacoma Power

Modesto Irrigation District

Hydro-Quebec TransEnergie

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Yes

Yes or No

Idaho Power Company

Organization

Question 5 Comment

65

The BARC SDT has assigned both Requirement R1 and Requirement R2 a “medium” VRF. Do you agree with the proposed VRF?
If not, please explain in the comment area below.

No

Yes or No

We believe the requirement itself is inappropriate, so any VRF is unnecessary.

Question 6 Comment

No

It is difficult to agree with the VRF’s while disagreeing with the standard as proposed.

Response: Thank you for your comment. Requirement R1 clarifies the requirement to return ACE to specified values following a
reportable balancing contingency event. This requirement already exists in the existing standard. Requirement R2 establishes the
requirement to operate with Contingency Reserve at least equal to the most severe single contingency, except for during specified

SERC OC Standards Review
Group

Response: Thank you for your comment. The SDT cannot determine from your comment what you believe to be unnecessary.
Requirement R1 clarifies the requirement to return ACE to specified values following a reportable balancing contingency event.
This requirement already exists in the existing standard. Requirement R2 establishes the requirement to operate with
Contingency Reserve at least equal to the most severe single contingency, except for during specified emergency operations
conditions. This requirement exists in existing standards, but without a clear definition of “most severe single contingency”. The
SDT has clarified the definition and the Requirement.

MRO NERC Standards Review
Forum

Organization

Summary Consideration: The majority of the negative commenters did not agree with the requirements and therefore could not
agree with the VRFs. The SDT explained that they could not determine from the comment what they believed to be
unnecessary. Requirement R1 clarifies the requirement to return ACE to specified values following a reportable
balancing contingency event. This requirement already exists in the existing standard. Requirement R2 establishes the
requirement to operate with Contingency Reserve at least equal to the most severe single contingency, except for
during specified emergency operations conditions. This requirement exists in existing standards, but without a clear
definition of “most severe single contingency”. The SDT has clarified the definition and the Requirement.

6.

Yes or No

Question 6 Comment

No

We can’t agree, due to the current lack of clarity in the requirements.

No

We believe the requirement itself is inappropriate, so any VRF is unnecessary.

No

We agree with the VRF for requirement R1 but do not agree with requirement R2 as
written. Thus, we do not agree with the VRF for Requirement R2.

No

We believe the requirement itself is inappropriate, so any VRF is unnecessary.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

67

Response: Thank you for your comment. The SDT cannot determine from your comment what you believe to be unnecessary.
Requirement R1 clarifies the requirement to return ACE to specified values following a reportable balancing contingency event.

IRC-SRC

Response: Thank you for your comment. The SDT cannot determine from your comment what you believe to be incorrect.
Requirement R2 establishes the requirement to operate with Contingency Reserve at least equal to the most severe single
contingency, except for during specified emergency operations conditions. This requirement exists in existing standards, but
without a clear definition of “most severe single contingency”. The SDT has clarified the definition and the Requirement.

ACES Standards Collaborators

Response: Thank you for your comment. The SDT cannot determine from your comment what you believe to be unnecessary.
Requirement R1 clarifies the requirement to return ACE to specified values following a reportable balancing contingency event.
This requirement already exists in the existing standard. Requirement R2 establishes the requirement to operate with
Contingency Reserve at least equal to the most severe single contingency, except for during specified emergency operations
conditions. This requirement exists in existing standards, but without a clear definition of “most severe single contingency”. The
SDT has clarified the definition and the Requirement.

MISO Standards Collaborators

Response: Thank you for your comment. Requirement R1 clarifies the requirement to return ACE to specified values following a
reportable balancing contingency event. This requirement already exists in the existing standard. Requirement R2 establishes the
requirement to operate with Contingency Reserve at least equal to the most severe single contingency, except for during specified
emergency operations conditions. This requirement exists in existing standards, but without a clear definition of “most severe
single contingency”. The SDT has clarified the definition and the Requirement.

Duke Energy

emergency operations conditions. This requirement exists in existing standards, but without a clear definition of “most severe
single contingency”. The SDT has clarified the definition and the Requirement.

Organization

Yes or No

Question 6 Comment

No

Agree with the the VRF for R1, but not R2 for the reasoons described in response to
Question 6.

Yes

It is difficult to agree with the VRFs while disagreeing with the standard as proposed.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

68

Response: Thank you for your comment. The SDT cannot determine from your comment what you believe to be unnecessary.
Requirement R1 clarifies the requirement to return ACE to specified values following a reportable balancing contingency event.
This requirement already exists in the existing standard. Requirement R2 establishes the requirement to operate with
Contingency Reserve at least equal to the most severe single contingency, except for during specified emergency operations
conditions. This requirement exists in existing standards, but without a clear definition of “most severe single contingency”. The
SDT has clarified the definition and the Requirement.

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

Response: Thank you for your comment. The SDT cannot determine from your comment what you believe to be incorrect.
Requirement R2 establishes the requirement to operate with Contingency Reserve at least equal to the most severe single
contingency, except for during specified emergency operations conditions. This requirement exists in existing standards, but
without a clear definition of “most severe single contingency”. The SDT has clarified the definition and the Requirement.

Seminole Electric Cooperative,
Inc.

This requirement already exists in the existing standard. Requirement R2 establishes the requirement to operate with
Contingency Reserve at least equal to the most severe single contingency, except for during specified emergency operations
conditions. This requirement exists in existing standards, but without a clear definition of “most severe single contingency”. The
SDT has clarified the definition and the Requirement.

Organization

Yes

Yes
Yes
Yes
Yes
Yes

Yes

Yes
Yes
Yes
Yes
Yes
Yes

Northeast Power Coodinating
Council

SPP Standards Review Group

seattle city light

ERCOT

Oklahoma Gas & Electric

Bonneville Power
Administration

Arizona Public Service
Company

Salt River Project

PacifiCorp

EnerVision, Inc.

Tucson Electric Power

Avista

NV Energy

No comment.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Yes

Yes or No

Manitoba Hydro

Organization

Question 6 Comment

69

Yes

Yes
Yes

Yes
Yes
Yes
Yes
Yes
Yes

Independent Electricity
System Operator

Energy Mark, Inc.

Portland General Electric
Company

ISO New England Inc.

American Electric Power

Tacoma Power

Texas Reliability Entity

Keen Resources Ltd.

Hydro-Quebec TransEnergie

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Yes

Yes or No

Idaho Power Company

Organization

Question 6 Comment

70

The BARC SDT has assigned both Requirement R1 and Requirement R2 a Time Horizon of “Real-time Operations”. Do you agree
with the Time Horizon the SDT has chosen? If not, please explain in the comment area below.

No

Yes or No
Same response as Question 6.

Question 7 Comment

No
Yes
Yes

Yes

Yes
Yes

Modesto Irrigation District

Manitoba Hydro

Northeast Power Coodinating
Council

MRO NERC Standards Review
Forum

SPP Standards Review Group

SERC OC Standards Review
Group

No comment.

Response: Thank you for your comment. Please refer to our response to Question #6.

Seminole Electric Cooperative,
Inc.

Organization

Summary Consideration: The vast majority of the commenters agreed with the use of “Real-time Operations” as the appropriate
time horizon.

7.

Yes
Yes
Yes

Yes
Yes
Yes
Yes
Yes

Yes

Duke Energy

MISO Standards Collaborators

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

ERCOT

ACES Standards Collaborators

Oklahoma Gas & Electric

IRC-SRC

Bonneville Power
Administration

Arizona Public Service
Company

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Yes

Yes or No

seattle city light

Organization

Question 7 Comment

72

Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes

Yes
Yes

Yes
Yes
Yes
Yes

PacifiCorp

PJM Interconnection, LLC

EnerVision, Inc.

Tucson Electric Power

Avista

NV Energy

Idaho Power Company

Independent Electricity
System Operator

Energy Mark, Inc.

Portland General Electric
Company

ISO New England Inc.

American Electric Power

Tacoma Power

Texas Reliability Entity

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Yes

Yes or No

Salt River Project

Organization

Question 7 Comment

73

Yes

Hydro-Quebec TransEnergie

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Yes

Yes or No

Keen Resources Ltd.

Organization

Question 7 Comment

74

The BARC SDT has developed VSLs for Requirement R1 and Requirement R2. Do you agree with the VSLs in this standard? If not,
please explain in the comment area.

Question 8 Comment
Requirement 1 should not be an event by event obligation. A quarterly measure has
worked quite well. We disagree with the current R2 so we cannot offer a suggestion
to improve its VSL.

Yes or No
No

No

Change all of the R1 VSLs to read ‘The Responsible Entity partially recovered...’

No

Requirement 1 should not be an event by event obligation. A quarterly average
measure has worked quite well. We disagree with the current R2 so we cannot offer
a suggestion to improve its VSL.

Response: Thank you for your comment. Currently, in all NERC/FERC investigations of events involving DCS compliance, they have

SERC OC Standards Review
Group

Response: Thank you for your comment; the drafting team has incorporated your suggestion.

SPP Standards Review Group

Response: Thank you for your comment. Currently, in all NERC/FERC investigations of events involving DCS compliance, they
have applied compliance and associated penalties on an event by event base.

MRO NERC Standards Review
Forum

Organization

Some commenters stated that the VSL implied that the entity had recovered from the event. The SDT agreed with the commenters
and modified the VSL to use the term “partially recovered”.

Summary Consideration: Many of the commenters disagreed with the use of an event by event measure. The SDT explained that
currently in all NERC/FERC investigations of events involving DCS compliance, they have applied compliance and
associated penalties on an event by event base.

8.

Yes or No

No

We can’t agree, due to the current lack of clarity in the requirements.

Question 8 Comment

No

Requirement 1 should not be an event by event obligation. A quarterly measure has
worked quite well. We disagree with the current R2 so we cannot offer a suggestion
to improve its VSL.

No

We disagree with the VSLs for both requirements. The VSLs for requirement R1 raise
the bar significantly for compliance without a technical justification. Today, DCS
compliance is determined by a quarterly average of response to events. Thus, failure
to recover ACE for two events within the same quarter would be a singular violation.
As proposed, the new VSLs would treat each event as a separate violation. Without
significant justification, we cannot agree with this change to the VSLs. Because we do
not agree with Requirement R2, we do not agree with the corresponding VSLs.

No

Requirement 1 should not be an event by event obligation. A quarterly measure has
worked quite well. We disagree with the current R2 so we cannot offer a suggestion
to improve its VSL.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

76

Response: Thank you for your comment. Currently, in all NERC/FERC investigations of events involving DCS compliance, they have
applied compliance and associated penalties on an event by event base.

IRC-SRC

Response: Thank you for your comment. Currently, in all NERC/FERC investigations of events involving DCS compliance, they have
applied compliance and associated penalties on an event by event base.

ACES Standards Collaborators

Response: Thank you for your comment. Currently, in all NERC/FERC investigations of events involving DCS compliance, they have
applied compliance and associated penalties on an event by event base.

MISO Standards Collaborators

Response: Thank you for your comment. The SDT has modified the requirements to provide for additional clarity.

Duke Energy

applied compliance and associated penalties on an event by event base.

Organization

No

Yes or No
BPA recommends changing the VSLs for R2 to: Lower VSL more than 2 but less than
or equal to 5 hours; Moderate VSL more than 5 but less than or equal to 10 hours;
High VSL more than 10 but less than or equal to 15 hours; Severe VSL More than 15
hours.

Question 8 Comment

No

No

The VSLs for Requirement R2 references “each calendar quarter” while the actual
requirement R2 does not require maintaining an amount of Contingency Reserve at
least equal to its Most Severe Single Contingency on a quarterly basis. Also, the
lower VSL starts with an entity being deficient for more than five hours. This poses a
gap; if for example, an entity was deficient between one and four hours.
ReliabilityFirst recommends restructuring the VSLs, to be consistent with the
language in the requirement, as follows (this is an example of a Lower VSL); “The
Responsible Entity maintain an amount of Contingency Reserve at least equal to its
Most Severe Single Contingency but its Contingency Reserve was deficient for less
than or equal to 15 hours.”

It is difficult to agree with the VSL’s while disagreeing with the standard as proposed.

No

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

77

Tacoma Power does not understand - all levels state that the Responsible Entity
recovered from the event, yet they recovered to less than 100% of the required
recovery. How can it be “recovered” without reaching 100% in every case? Instead,
we suggest that the VSLs recognize that the Responsible Entity “partially recovered”
from the event.

Response: Thank you for your comments. The drafting team has provided clarifying language.

Tacoma Power

Response: Thank you for your comments. The drafting team has provided clarifying language.

ReliabilityFirst

Response: Thank you for your comment.

PJM Interconnection, LLC

Response: Thank you for your comments. The SDT believes that the current ranges in the VSL for R2 are more appropriate.

Bonneville Power
Administration

Organization

No

Yes or No

1) R1 VSL- At what point is the ACE measured in order to determine the % of required
recovery. We assume it is the lowest ACE value measured during the one-minute
period for the Balancing Contingency Event, but this should be clarified.2) R2 VSL - A
deficiency less than 5 hours is not covered by the VSL. If the intent is to allow a
certain amount of deficiency without penalty, that should be clearly stated in the
requirement and not implied in the VSL.3) R2 VSL - Five hours in a calendar quarter of
not having sufficient Contingency Reserves seems too long, especially since
Contingency Event Recovery Periods and EEAs are excluded. We would recommend a
shorter time frame, e.g. 0-3 hours for lower VSL, 3-5 for moderate VSL, 5-10 for high
VSL, and >10 for severe VSL. Also, the time frame for each VSL level needs to state if
it is cumulative or on a per-event basis (we assume it is cumulative but it should be
explicitly stated).

Question 8 Comment

Yes

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

Requirement 1 should not be an event by event obligation. A quarterly measure has
worked quite well. We disagree with the current R2 so we cannot offer a suggestion
to improve its VSL.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

78

Response: Thank you for your comment. Currently, in all NERC/FERC investigations of events involving DCS compliance, they

No

Seminole Electric Cooperative,
Inc.

Response: Thank you for your comments. The drafting team has provided clarifying language.

Texas Reliability Entity

Organization

Yes or No

Yes

Yes
Yes
Yes

Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes

Yes

Northeast Power Coodinating
Council

ERCOT

Oklahoma Gas & Electric

Arizona Public Service
Company

Salt River Project

PacifiCorp

EnerVision, Inc.

Tucson Electric Power

Avista

NV Energy

Idaho Power Company

Independent Electricity
System Operator

Energy Mark, Inc.

No comment.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Yes

Manitoba Hydro

have applied compliance and associated penalties on an event by event base.

Organization

Question 8 Comment

79

Yes
Yes
Yes

American Electric Power

Keen Resources Ltd.

Hydro-Quebec TransEnergie

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Yes

Yes or No

Portland General Electric
Company

Organization

Question 8 Comment

80

The BARC SDT has made significant modifications to the Background Document based on industry comments received. Do you
agree that these modifications provide additional clarity as to the development of this standard? If not, please explain in the
comment area.

No

Yes or No

SPP Standards Review Group

No

Response: Thank you for your comment.

MRO NERC Standards Review
Forum

Organization

Page 4 1st paragraph under Contingency Reserve

2nd paragraph1st line - remove space following ‘Policy’ and insert space after the
period

1st paragraph 2nd line - replace ‘They’ with ‘It’4th line - remove the hyphen in ‘15minute’

We offer the following suggestions:Page 3

There first needs to be agreement on the requirements before there is concurrence
with the background document.

Question 9 Comment

Manu of the commenters stated that since they disagreed with the requirements then they could not agree with the Background
Document. The SDT explained that they had made modifications to the requirements and added clarifying language to
the Background Document.

Summary Consideration: Some of the commenters wanted additional information as to how the threshold of 500 MW was
determined. The SDT explained that they had removed the 500 MW threshold for all Interconnections and was now
using a threshold unique to each Interconnection. They further stated that they had added language to the
Background Document to provide additional clarity on the thresholds.

9.

Yes or No

Page 10 Last paragraph Needs to be rewritten; what’s there refers to R1 not R2.

Under Violation Severity Levels This needs to be rewritten. The VSLs are based solely
on amount of recovery. The paragraph tries to include the sufficiency of response but
it’s not in the VSLs.

5th paragraph Reword the 2nd sentence to read: ‘Reviewing the data, the drafting
team decided to establish a single, continent-wide standard on the median value of
generation loss.’

3rd paragraph 1st line - delete space in R1

Page 6 2nd paragraph Capitalize Contingency Reserve

Page 5 Correct the text formatting for Requirement 1

6th & 7th lines - be consistent with the hyphens in demand side management

2nd line - replace ‘its’ with ‘their’

Question 9 Comment

No

82

The Background Document states on page 4 that “FERC Order 693 (at P355) directed
entities to include a Requirement that measures response for any event or
contingency that causes a frequency deviation.” We disagree with this interpretation
of the Commission’s directive. In Order 693 (P355) the Commission declined to define
a ‘significant deviation as a frequency deviation of 20 mHz’, but instead directed the
ERO ‘to define a significant deviation and a reportable event’. The Commission
directed that ‘loss of supply, loss of load and significant scheduling problems, which
can cause frequency disturbances,’ must be taken into account when developing the
aforementioned definitions. We believe that the Commission clearly did not intend
that any event that causes a frequency deviation, not matter how small, be included

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

SERC OC Standards Review
Group

The SDT has modified the VSL to provide additional clarity.

Response: Thank you for your comment. The drafting team has revised the background document incorporating the majority of
you suggestions.

Organization

Yes or No

in DCS reporting, but rather that a significant frequency deviation be defined by the
ERO. The definition of a Reportable Balancing Contingency Event should, but
currently does not, reflect such a definition. The Background Document on page 6
points to statistical frequency data supplied by CERTS in Attachment 1 to support the
500 MW reporting threshold. While Attachment 1 shows the box plots used for this
determination, it does not provide a narrative defining the sampling data or method.
It appears that frequency deviations resulting from loss of load and loss of supply
were included in the same data sample. We question whether this is appropriate and
believe that in order for the industry to effectively evaluate the proposed criteria, a
narrative needs to be added to Attachment 1 that explains the data sample and
method. We suggest that additional details be provided in the Background Document
relating to the methodology for development of the reporting thresholds.

Question 9 Comment

No

It is not clear to the PPL NERC Registered Affiliates why the SDT chose to use the loss
of load (negative loss values included in the CERTS statistics) when determining the
reportable threshold for BAL-002. The document fails to include the criteria that
were used to define a “significant impact on frequency”.

No

There first needs to be agreement on the requirements before there is concurrence
with the background document.

No

83

The Background Document states on page 4 that “FERC Order 693 (at P355) directed
entities to include a Requirement that measures response for any event or

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Southern Company: Southern
Company Services, Inc.;

Response: Thank you for your comment. The SDT would need additional information to provide a response. The SDT has made
significant modifications to the standard and the Background Document,

MISO Standards Collaborators

Response: Thank you for your comment. The drafting team has incorporated your comment and modified the standard.

PPL NERC Registered Affiliates

The SDT has modified the Background Document to provide additional clarity as to how the thresholds were developed.

Response: Thank you for your comment. The SDT has modified the standard to accommodate your comment.

Organization

Yes or No

contingency that causes a frequency deviation.” We disagree with this interpretation
of the Commission’s directive. In Order 693 (P355) the Commission declined to define
a ‘significant deviation as a frequency deviation of 20 mHz’, but instead directed the
ERO ‘to define a significant deviation and a reportable event’. The Commission
directed that ‘loss of supply, loss of load and significant scheduling problems, which
can cause frequency disturbances,’ must be taken into account when developing the
aforementioned definitions. We believe that the Commission clearly did not intend
that any event that causes a frequency deviation, no matter how small, be included in
DCS reporting, but rather that a significant frequency deviation be defined by the
ERO. The definition of a Reportable Balancing Contingency Event should, but
currently does not, reflect such a definition. The Background Document on page 6
points to statistical frequency data supplied by CERTS in Attachment 1 to support the
500 MW reporting threshold. While Attachment 1 shows the box plots used for this
determination, it does not provide a narrative defining the sampling data or method.
It appears that frequency deviations resulting from loss of load and loss of supply
were included in the same data sample. We question whether this is appropriate and
believes that in order for the industry to effectively evaluate the proposed criteria, a
narrative needs to be added to Attachment 1 that explains the data sample and
method.We suggest that additional details be provided in the background document
relating to the methodology for development of the reporting thresholds.

Question 9 Comment

No

84

(2) There is a statement on page 5 just before the Rationale by Requirement section
that there are other definitions that have been added or modified. An explanation of
what these are would be helpful.

(1) The background document needs to explain the conflict between BAL-002 and
EOP-002 in detail rather than just stating that a conflict exists.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

ACES Standards Collaborators

The SDT has modified the Background Document to provide additional clarity as to how the thresholds were developed.

Response: Thank you for your comment. The SDT has modified the standard to accommodate your comment.

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

(3) The formulas starting on page 8 are overly complicated in an attempt to address
the few situations where there are additional generator contingencies that occur
shortly before or during the ACE recovery window. We suggest starting with simple
formulas that consider that predominant situation where only one generator
contingency occurs. Then build the more complicated formulas on that. It will be
easier to explain. We also suggest using pictures to explain the formulas. For
example, a graph showing the loss of a unit before and after the current contingency
would help explain the formulas. The graph should include labels such as what
ACE_BEST, ACE_PRE, and MEAS_CR_RESP are.

Question 9 Comment

No

There first needs to be agreement on the requirements before there is concurrence
with the background document.

No

85

The Background Document states on page 4 that “FERC Order 693 (at P355) directed
entities to include a Requirement that measures response for any event or
contingency that causes a frequency deviation.” PJM disagrees with this
interpretation of the Commission’s directive. In Order 693 (P355) the Commission
declined to define a ‘significant deviation as a frequency deviation of 20 mHz’, but
instead directed the ERO ‘to define a significant deviation and a reportable event’.
The Commission directed that ‘loss of supply, loss of load and significant scheduling
problems, which can cause frequency disturbances,’ must be taken into account
when developing the aforementioned definitions. PJM believes that the Commission
clearly did not intend that any event that causes a frequency deviation, not matter

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

PJM Interconnection, LLC

Response: Thank you for your comment. The SDT would need additional information to provide a response. The SDT has made
significant modifications to the standard and the Background Document.

IRC-SRC

3 - The SDT understands your concern and that is why they have provided a spreadsheet to assist you in the calculation.

1 & 2 - The drafting team has modified the background document attempting to address your issues.

Response: Thank you for your comment.

Organization

Yes or No

how small, be included in DCS reporting, but rather that a significant frequency
deviation be defined by the ERO. The definition of a Reportable Balancing
Contingency Event should, but currently does not, reflect such a definition. The
Background Document on page 6 points to statistical frequency data supplied by
CERTS in Attachment 1 to support the 500MW reporting threshold. While
Attachment 1 shows the box plots used for this determination, it does not provide a
narrative defining the sampling data or method. It appears that frequency deviations
resulting from loss of load and loss of supply were included in the same data sample,
skewing the results. PJM believes that in order for the industry to effectively evaluate
the proposed criteria, a narrative needs to be added to Attachment 1 that explains
the data sample and method.

Question 9 Comment

No

It is unclear whether or not the guidance document will eventually become a part of
the officially posted standard (in an appendix for example).

No

86

The equations and methodology on CR Form 1 seem flawed. The recovery
requirement in R1 is based on ACE, but the calculations in CR Form 1 are based on
the MW lost. We believe the equations in CR Form 1 and the Background Document
should be modified to incorporate the elements of the ACE equation into the
calculations (i.e. frequency deviation and frequency bias in particular). For example,
a recent unit trip of 1300 MW occurred. Based on the frequency deviation, the
lowest ACE during the one-minute event period was -1900 MW. The language of the
requirement and the CR Form 1 should reflect the recovery of the ACE (1900 MW)
rather than the MW lost (1300 MW) in this case.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Texas Reliability Entity

Response: Thank you for your comment. The Background Document will not be a part of the standard. The spreadsheet that the
SDT has developed will be part of the standard.

American Electric Power

The SDT has modified the Background Document to provide additional clarity as to how the thresholds were developed.

Response: Thank you for your comment. The SDT has modified the standard to accommodate your comment.

Organization

Yes or No

Question 9 Comment

No

The definition of "Best ACE" is unclear as: the "most positive ACE during the
Contingency Event Recovery Period occurring after the last subsequent event, if any
(MW)". The meaning of "if any" is specified only in the attached spreadsheet that
makes "claiming" such a subsequent event "optional" to the BA. In other words, a BA
will not claim a subsequent event that makes the BA's compliance worse. The
purpose of this definition of "Best ACE" is to prevent R1's sanctioning a BA's avoiding
non-compliance due to insufficient reserve, by incurring a subsequent contingency
within the recovery period to reduce the BA's recovery requirement. By this
definition of "Best ACE" a BA will not claim a subsequent event that makes the BA's
compliance worse. A clearer alternative definition of "Best ACE", that does not
require the "optionality" obscurely lodged in the spreadsheet and that would
harmonize with the needed change to the R1 wording that I show in my Comment to
Question 10, would be "the least negative value if there are no positive values, or the
most positive value of any positive values, among the values of ACE occurring during
the recovery period, unless it is the ACE to which the addition of any subsequent
events that occurred prior to or concurrently with it results in a value that is the least
negative value if there are no positive values, or the most positive value of any
positive values, among all such resultant values and the other ACE values during the
recovery period.”

Yes

very helpful

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Tucson Electric Power

87

Response: Thank you for your comment. The SDT discussed your proposed method during the drafting of the standard but chose
to not pursue this due to the complexities involved.

Keen Resources Ltd.

Response: Thank you for your comment. The SDT discussed this relationship between frequency bias and ACE. In your example we
believe the additional 600 MW of ACE deflection is due to the delta in your actual frequency response and the frequency bias in the
ACE equation. As the MW’s lost is replaced by deployment of contingency reserves, the frequency would return back toward 60 hz
which would assist in returning ACE toward 0. The MW’s lost is the amount of contingency reserves that need to be deployed to
restore balance to the interconnection. The measurement of recovery from a loss is still best reflected in ACE.

Organization

Yes

Yes or No
No comment.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Manitoba Hydro

Organization

Question 9 Comment

88

ACES Standards Collaborators

Organization

Yes or No

(1) We cannot support a 500 MW threshold for a Reportable Balancing Contingency

Question 10 Comment

A couple of commenters wanted the SDT to use BAAL as the measure for performance in this standard. The SDT stated that they
considered using the approach of BAAL as the basis for performance but chose the present method since concerns
other than frequency performance may need to be addressed. There is also a compelling interest in measuring the
adequacy of reserve.

Several commenters believed that there should only be two requirements in the standard, recover from a reportable event and
replenish reserves. The SDT explained that they had preserved the two requirements that were identified within
Requirement R1 and R2. In addition, the proposed Requirement R2 preserves the existing requirement to maintain
reserve equal to MSSC (present Requirement R3.1).

A few commenters stated that BAAL would handle Balancing Contingency Events and therefore this standard was not necessary. The
SDT explained that they agreed that BAAL would handle DCS within a 30 minute interval as it was voted on back in
2007. However, elimination of BAL-002 has not been supported by the industry in the past.

Some commenters were confused as to how to calculate a Reserve Sharing Group Reporting ACE. The SDT modified the definition to
state that it was the algebraic sum of the BAs participating at the time of the event Reporting ACEs or equivalent.

Many commenters question why the SDT was not using the term Reportable Disturbance. The SDT explained that the term
Disturbance as defined by the NERC Glossary of Terms is extremely broad and not specific. The term Balancing
Contingency Event was defined to allow the SDT to be more specific as to what should be considered for purposes of
this standard.

Summary Consideration: Several commenters disagreed with the use of 500 MW as a threshold for reporting a disturbance for all
Interconnections. The SDT modified the threshold to use a value unique to each Interconnection.

10. If you are not in support of this draft standard, what modifications do you believe need to be made in order for you to support
the standard? Please list the issues and your proposed solution to the issue.

Organization

Question 10 Comment

90

(4) The drafting team has an opportunity to assist NERC in moving the Reliability
Assurance Initiative along and showing some of the first fruits of the initiative. One

(3) The purpose needs to be modified. Please strike “balances resources and
demand and”. The purpose of the standard is to recover ACE following a Reportable
Balancing Contingency Event. The portion that needs to be struck is addressed by
BAL-001.

(2) Additional justification is necessary to change the pre-disturbance calculation
from an average of 10 to 60 seconds of ACE data prior to the disturbance to a 16second interval. There is no explanation of this in the background document and we
cannot support such a change without a justification for how it supports reliability.
Furthermore, it is not consistent with BAL-005-0.2b which requires ACE calculation on
at least a six second basis. A BA using a six-second sample rate could be viewed as
being out of compliance if they used either two (12 seconds) or three (18 seconds)
samples since they cannot use exactly 16 seconds of data. Furthermore, using only
two or three samples could lead to unrealistic averages particularly if there are any
glitches in the data. What does an entity do if a scan was skipped or there was a data
spike? More samples would make it less likely for this to be an issue.

Event. The number is arbitrary without any technical justification. The background
document explains how the drafting team reviewed CERTS data to arrive at the
conclusion that a 100 MW threshold would cover all frequency events. Correctly, the
drafting team determined that this was simply an unrealistic threshold and would not
provide any additional reliability value. The background document then explains
that the drafting team decided “to capture the majority of events having significant
impact on frequency” by setting the threshold to 80% of the MSSC or 500 MW. It did
not explain which value would do this or why it was important “to capture the
majority of events”. Furthermore, there is no explanation why 500 MW is necessary
when today 80% of MSSC is used. Has the use of 80% of MSSC resulted in an
unreliable system? Thus, we can only conclude the value is arbitrary. Please remove
the 500 MW value.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Yes or No

Organization

Question 10 Comment

91

(5) The data retention section is inconsistent with the NERC Rules of Procedure.
Section 3.1.4.2 of Appendix 4C - Compliance Monitoring and Enforcement Program
states that the compliance audit will cover the period from the day after the last
compliance audit to the end date of the current compliance audit. Since a BA is on a
three-year audit cycle, the period from the previous audit will be about 3 years. It
could be a little more or a little less. However, the data retention section of “the
current year, plus three previous calendar years” (which could be up to four years)
actually could exceed this three year audit cycle period. Consider if a BA completed
their last audit on November 15, 2010. Their audit cycle would require another audit
in 2013. Let’s assume this is scheduled for December 15, 2013. This means the audit
period is 3 years and 1 month. It also means per the Rules of Procedure that NERC

of the key white papers written for the initiative focuses on the reducing the data
requirements and retention periods necessary for the compliance and enforcement
process. NERC compliance has a stated goal of reducing the data retention burden
on registered entities. The data retention required for the current versions of this
standard exceed what is necessary and this draft version perpetuates the problem.
All BAs currently must submit monthly data to their regional entities for this standard
which clearly shows whether they are compliant or not. Then they are still required
to retain three years worth of data. Since the regional entities already have the data
and know whether they are compliant or not, what reliability value does three years
of data provide? None. The new version will only perpetuate this issue. In response
to our previous comments, the drafting team indicated that the monthly reporting is
not required by the standard and is up to the region. While this is true, it is highly
unlikely that the regional entities will change this monthly reporting burden given
that the standard is conceptually the same as the existing standard. Furthermore,
the drafting team and NERC staff can review the issue with regional entity
compliance personnel to confirm their plans for monthly reporting. If they do plan to
continue with the monthly reporting, then no more than six months of data is
necessary and we request that the standard should be changed. It will demonstrate a
good faith effort on the part of NERC to move the RAI forward.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Yes or No

Yes or No

(8) Thank you for the opportunity to comment.

(7) There is no explanation for why Reportable Disturbance is not a satisfactory
definition as used in the existing standard and why it is replaced with Reportable
Balancing Contingency Event. Furthermore, it is not proposed to be retired. If the
term will no longer be used, it should be retired.

(6) The VSLs for Requirement R2 need to be justified. There is no explanation
provided for the values chosen for the various thresholds. For example, the Lower
VSL covers contingency deficiency for a period of 5 to 15 hours. Why shouldn’t this
go to 20, 30, 40 or any other number of hours? Without a justification, we can only
assume the numbers were selected arbitrarily. We are also confused by the Lower
VSL since it starts at 5 hours. Does this mean that a BA can be deficient of
contingency reserves up to 5 hours without a violation occurring?

cannot review any period prior to November 15, 2010 for compliance unless there is
an outstanding investigation. Per the data retention section, on December 15, 2013,
the date of the audit, the BA would have to retain data for all of 2013 as well as all of
the data for 2010, 2011 and 2012. By the Rules of Procedure, the auditors could not
review any data prior to November 15, 2010. Thus, the registered entity would be
compelled to retain for 11.5 months for which NERC is not allowed to review. How
does this benefit reliability? The data retention period should be changed to retain
data since the last audit. Changing the data retention period to be no longer than
since the last audit would show a good faith effort in moving the RAI along.

Question 10 Comment

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

92

1) The SDT has modified the standard to provide individual interconnection reporting thresholds.
2) The change from 10 to 60 with 4 scans to the 16 seconds prior to event was meant to clarify the pre-event data and provide
consistency with BAL-003-1. The SDT has modified the Background Document to provide additional clarity.
3) The Purpose Statement does reflect recovery of ACE since ACE recovery is intended to provide the necessary indication to
assure the balancing of resource and demand.
4) & 5) The SDT does not have control over what the regions require for reporting. The SDT believes that your comment is outside

Response: Thank you for your comment.

Organization

Yes or No

Question 10 Comment

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

93

5) How do you calculate a Reserve Sharing Group Pre-Reportable Contingency Event
ACE Value? We assume it is the algebraic sum of the ACEs of the BAs that make up
the Reserve Sharing Group, but it may need to be explicitly stated.

4) The Reserve Sharing Group Reporting ACE definition is different here than the
Regulation Reserve Sharing Group Reporting ACE definition provided in BAL-001-2,
which is correct? (i.e. Does not have “at the time of measurement” as last part of
sentence).

3) Does the SDT intend to retire the existing “Disturbance Control Standard”
definition? Do you need to modify definition of “Reserve Sharing Group” to not
reflect usage of “Disturbance Control Performance”?

2) R1, as stated, is an event-by-event obligation. A failure to recover for one event
would constitute a violation, even though the Responsible Entity may have
performed well for the remainder of the period. Is this the intent of the SDT? Would
the SDT consider another measure, such as evaluation of multiple events on a
quarterly basis?

1) In ERCOT, we have an existing process in place to analyze unit trips greater than
500MW. However, other interconnections may find it overly burdensome to analyze
these unit trips based on their current size and loads.

1) The SDT has modified the standard to provide individual interconnection reporting thresholds.

Response: Thank you for your comment.

Texas Reliability Entity

the scope of the drafting team.
6) The SDT agrees that the selection of 5 hours could be considered arbitrary and is based on the judgment of the SDT. The SDT
has modified the requirement and the Background Document to provide consistency and additional clarity.
7) The term Disturbance as defined by the NERC Glossary of Terms is extremely broad and not specific. The term Balancing
Contingency Event was defined to allow the SDT to be more specific as to what should be considered for purposes of this
standard. We have addressed the term Reportable by providing individual interconnection thresholds. The term Reportable
Disturbance is presently used in other standards and therefore cannot be retired at this time.

Organization

Yes or No

Question 10 Comment

A technical justification for the "16 second interval" for ACE and the "105 minutes"
value for Contingency Reserve demonstration needs to be added.

Duke Energy

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

94

o As the BAAL proposed in BAL-001-2 will address the loss of any resource, or any
other change in ACE causing a Balancing Authority to exceed its BAAL, it could be
argued that there is no reliability need to retain DCS. In 2007, the NERC Operating
Committee supported the adoption of the BAAL and a subsequent field trial of
operating without DCS to determine if the Standard was still needed. Until more
experience is gained under the BAAL, Duke Energy supports having a Standard driving
a Balancing Authority to address the largest of its events as it does today, however
we see no reliability need to expand BAL-002 beyond the simple concept of
measuring the recovery to the largest of the BA’s resource losses - 80% or greater of
the MSSC, and limited to MSSC, where the applicable events are clearly understood
by the operator. Duke Energy disagrees with applying compliance and associated
compliance reporting on an event-by-event basis, rather than allowing the quarterly
reporting currently provided under BAL-002. The measures for compliance should
recognize that no technical basis has been provided to support the 15-minute
recovery required under Requirement R1 - compliance to a line drawn in the sand can
be measured on a quarterly basis similar to today, as real-time reliability needs will

Response: Thank you for your comment. The background document has been modified to include a discussion on the 16 second
interval. The 105 minutes is the current time for DCS and comes from the 15 minutes of the event and the 90 recovery period.

Modesto Irrigation District

2) Currently, in all NERC/FERC investigations of events involving DCS compliance, they have applied compliance and associated
penalties on an event by event base.
3) The SDT has modified the standard to eliminate the need to retire the existing Disturbance Control Standard definition or
modify the definition for Reserve Sharing Group.
4) The SDT has made the necessary corrections.
5) The SDT has modified the definition for Reserve Sharing Group Reporting ACE to be the algebraic sum of the Reporting ACEs or
equivalent.

Organization

Yes or No

o Duke Energy believes that Reserve Sharing Group should have the flexibility to
calculate a group ACE rather than just taking the algebraic sum of all the BA ACEs.

o Duke Energy disagrees with the definition of “Reportable Balancing Contingency
Event”. Given that all resource losses will be captured by the BAAL under BAL-001-2,
that there is no basis for using 500 MW as a baseline for reporting, and that there has
not been a demonstrated reliability need to move away from our current reporting
criteria of 80% or greater of the MSSC, Duke Energy does not support the inclusion of
the 500 MW threshold in the definition.. We believe that BAAL 30-minute response
covers all events, and DCS action is a 15-minute response intended to address large
events. We agree with MISO’s comment that currently DCS is measured quarterly,
and the proposed Requirement R1 creates an unnecessary event-by-event
compliance evaluation. Adding the 500 MW threshold and multi-contingent event
expectation is excessive, with no benefit to reliability.

be met by the BA being held to compliance under BAAL.

Question 10 Comment

95

(1) Definitions, Reportable Balancing Contingency Event - there is no definition within
the standard or Glossary as to what ‘EMS scan rate data’ is.

Although Manitoba Hydro is in support of this standard, we have the following
clarifying comments:

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Manitoba Hydro

The SDT has modified the definition for Reserve Sharing Group Reporting ACE to be the algebraic sum of the Reporting ACEs or
equivalent.

The BARC SDT has modified the standard to provide for the reporting threshold to be on an Interconnection by Interconnection
basis.

Response: The BARC SDT acknowledges that BAAL would handle DCS within a 30 minute interval as it was voted on back in 2007.
However, elimination of BAL-002 has not been supported by the industry in the past. In addition, currently in all NERC/FERC
investigations of events involving DCS compliance, they have applied compliance and associated penalties on an event by event
base.

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Organization

Question 10 Comment

96

(9) VRF/VSL - capitalize ‘bulk electric system’ in both the High Risk Requirement and

(8) M1 - the word ‘including’ should be replaced with ‘as well as’ if the ‘additional
documentation’ that needs to be provided is in addition to the CR Form 1, not that
the additional documentation forms part of the CR Form 1.

(7) R2 - some of the terminology appears to be incorrect within this requirement. Is
‘Disturbance Recovery Period’ meant to be ‘Contingency Event Recovery Period’? Is
‘Contingency Reserve Recovery Period’ meant to be ‘Contingency Reserve
Restoration Period’?

(6) R1, R2 - both ‘MSSC’ and ‘Most Severe Single Contingency (MSSC)’ are used
throughout the standard. The words ‘Most Severe Single Contingency (MSSC)’ should
be used at the first instance and then the acronym ‘MSSC’ for all instances thereafter.

(5) R1 - as written, R1 requires that the Responsible Entity demonstrate that ACE was
returned to a certain value. The demonstrate aspect of the requirement seems more
of a measure than a requirement. In other words, the requirement should be that
the Responsible Entity return the ACE to a certain value, the measure is that they
provide evidence to demonstrate that they did so.

(4) 1. (Proposed) Effective Date in both Standard and Implementation Plan - remove
the “ ‘ “ following the word ‘Trustees’ because it is not defined this way in the
Glossary of Terms.

(3) Section D, Compliance, 1.1 - the paraphrased definition of ‘Compliance
Enforcement Authority’ from the Rules of Procedure is not the standard language for
this section. Is there a reason that the standard CEA language is not being used?

(2) Definitions, Contingency Event Recovery Period - the definition does not clearly
define exactly when the Contingency Event Recovery Period begins. As written, the
definition seems to indicate that this period begins at two different times (i) when
the resource output begins to decline and (ii) in the first one minute interval of a
Balancing Contingency Event. Please clarify.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Yes or No

Yes or No

(11) VSL, R2 - the language of the VSL does not track the language of the requirement
or measure. The VSL refers to calendar quarters, while the requirement and measure
do not.

(10) VSL, R1 - the language of the VSL does not track the language of the requirement
or measure. The VSL refers to ‘recovering from an event’ while the requirement
refers to returning ACE to a certain level.

Medium Risk Requirement sections.

Question 10 Comment

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

11 – The SDT has modified the language used in Requirement R2.
97

10 – Recovery from an event is returning your ACE to the conditions defined in Requirement R1. Therefore, recovery is
incorporated into satisfying R1.

9 – The SDT has corrected the error that you have identified.

8 – The SDT has modified the measure to provide additional clarity.

7 – The SDT realized that the incorrect terms had been used in this posting. This has been corrected.

6 – The SDT spelled the phrase out for clarity and emphasis.

5 – The SDT agrees with your comment and has made the necessary modifications.

4 - The language that is being used in this draft of the standard is the latest NERC approved language for Effective Date.

3 – The language that is being used in this draft of the standard is the latest NERC approved language for Compliance Enforcement
Authority.

2 – The definition, as presently written, is very clear and is intended to be read as written. The Contingency Event Recovery Period
begins at the time specified and is to be read as one entire clause which is why it is not otherwise punctuated. In other words, the
phrasing should not be broken into two parts.

1 – The SDT understands that the phrase “EMS scan rate data” is used in several other standards (i.e., BAL-005 and BAL-003-1) and
is a commonly used term within the industry.

Response: Thank you for your comment.

Organization

Yes or No
BAL-002, R1 states that the Responsible Entity shall demonstrate that it returned its
ACE to zero (less some modifiers); in other words, the standard requires ACE to be
returned to an absolute number, without a tolerance. I believe this is not the intent
of the SDT, that they probably meant zero or positive, or something like that; but,
reading the requirement literally, I believe it would be difficult to prove compliance
using integrated values for ACE that will likely not equal zero.

Question 10 Comment

98

Preserve the two true requirements today (recover from reportable events within
15 minutes and replenish reserves in 90 minutes).

The SAR for the drafting team was basically to clean up the V0 clutter in the standard
and address Order No 693 directives. The only two true requirements in the V0
standard are to recover from reportable events in 15 minutes and replenish reserves
within 90 minutes. These should be the basis of BAL-002-1. Our recommendations
are:

Besides the concerns presented above, we are troubled with the significant changes
that will occur within R1 compared to today’s DCS and the fact that the drafting team
is asking no questions about those changes. The current DCS is measured on a
quarterly basis. The way the proposed requirement 1 and VSL are crafted, this is now
an event by event compliance evaluation. When you add the fact that the team is
also embedding a 500 MW reporting threshold and the multi-contingent event
expectation, this exposes the industry to a heavy-handed standard for no reliability
need. It should be noted that DCS performance has been stellar across North
America compared to what existed under Policy 1. The changes being implemented
are well beyond what was in the drafting team’s SAR and the Order No. 693
directives. Recommend that each interconnection has a different MW level, due to
the sheer size of each interconnection. As an Eastern Interconnection entity, we
recommend 900 MW vise 500 MWs.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

MRO NERC Standards Review
Forum

Response: Thank you for your comment. The SDT has modified the language in Requirement R1 to address your concern.

Florida Municipal Power
Agency

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Organization

Question 10 Comment

99

The drafting team is proposing to continue to use only ACE under Requirement R1 as
the measure of reliability in the determination of Balancing Authority or RSG
compliance. As has been seen in actual operation, the current methodology can lead
to and has caused RC directives to drop load when there was not a reliability issue,
defined as a frequency concern or transmission line loading issue. ACE is not a
primary measure of reliability, only equity. To remedy this deficiency in the proposed

The standard should be based on the lesser of 80% of MSSC, 1000MW, or a lower
value chosen by the Balancing Authority.

o The continent-wide contingency reserve policy should be a separate guidance
document under the purview of the NERC Operating Committee with comments
collected under the standards process along with this standard. This meets the 693
directive. The policy document should provide guidance on how the BA should assess
the necessary amount of reserves as well as provide simple definitions of the
different types of reserves. Once these terms are defined and commented on by the
Industry in the policy, NERC should add these four types of reserves to “Attachment
1-TOP-005 Electric System Reliability Data” with the expectation in the policy that
Reliability Coordinators collect this information in real time for use in the EEA
process. The policy could ask the BAs to initially review and assess their needs and
relay this to their RC. The policy would be available for re-review if the BA’s
performance approaches non-compliance.

o Due to concerns we have in BAL-013, we believe the reporting form for BAL-002
should also have a reporting slot for large loss of load events (Order No. 693
directive), but for reasons we state in BAL-013, believe that these should be excluded
from compliance evaluation.

Provide clarity in the compliance section of the standard or the background
document how events > MSSC are reported. Note: We believe it is acceptable to
put something in the compliance section of the standard that notes if the same
event > than MSSC occurs within 3 years, the BA should be held to the DCS for
that contingency.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Yes or No

Yes or No

standard, the drafting team should utilize the BAAL limit as a more appropriate
measure of response to the sudden loss of generation, not pre-event ACE or zero,
whichever is lower. As proposed by the NSRF, this does not do away with DCS as
originally proposed under BAAL but would change the measure of compliance in the
DCS process to a more appropriate, reliability based measure. The NSRF is also not
proposing to change the 15-minute period in BAL-002 for a reportable event with this
modification.

Question 10 Comment

10
0

Besides the concerns presented above, we are troubled with the significant changes
that will occur within R1 compared to today’s DCS and the fact that the drafting team
is asking no questions about those changes. The current DCS is measured on a
quarterly basis. The way the proposed requirement 1 and VSL are crafted, this is now

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

MISO Standards Collaborators

1. The BARC SDT has modified the standard to provide for the reporting threshold to be on an Interconnection by
Interconnection basis.
2. The SDT has preserved the two requirements that you have identified within Requirement R1 and R2. In addition, the
proposed Requirement R2 preserves the existing requirement to maintain reserve equal to MSSC (present Requirement R3.1).
3. This standard is designed to measure performance of your contingency reserve for Balancing Contingency Events up to your
MSSC. This does not relieve you from meeting all of the other NERC reliability standards during these events. While the SDT
understands your concern about single contingencies greater than MSSC, the SDT has chosen to use a single pre-determined
contingency as the basis for this standard since it is well defined within the industry.
4. The SDT agrees with the industry with regards to the need for BAL-013-1. The SDT has chosen to stop development on a Large
Loss of Load standard (BAL-013-1) and believes that the loss of a large load is covered in BAL-001-2 Requirement R2 (BAAL).
5. The SDT is developing a Reserve Guideline for approval and posting by the NERC OC.
6. The BARC SDT has modified the standard to provide for the reporting threshold to be on an Interconnection by
Interconnection basis.
7. The SDT considered using the approach of BAAL as the basis for performance but chose the present method since concerns
other than frequency performance may need to be addressed. There is also a compelling interest in measuring the adequacy
of reserve.

Response: Thank for your comments.

Organization

Organization

Question 10 Comment

10
1

an event by event compliance evaluation. When you add the fact that the team is
also embedding a 500 MW reporting threshold and the multi-contingent event
expectation, this exposes the industry to a heavy-handed standard for no reliability
need. It should be noted that DCS performance has been stellar across North
America compared to what existed under Policy 1. The changes being implemented
are well beyond what was in the drafting team’s SAR and the Order No. 693
directives.The SAR for the drafting team was basically to clean up the V0 clutter in the
standard and address Order No 693 directives. The only two true requirements in
the V0 standard are to recover from reportable events in 15 minutes and replenish
reserves within 90 minutes. These should be the basis of BAL-002-1. A Contingency
Reserve Policy Guideline document in conjunction with the recommendations below
should be sufficient to meet the drafting team SARs and the directives: o Preserve
the two true requirements today (recover from reportable events within 15 minutes
and replenish reserves in 90 minutes). o Provide clarity in the compliance section of
the standard or the background document how events > MSSC are reported. Note:
We believe it is acceptable to put something in the compliance section of the
standard that notes if the same event > than MSSC occurs within 3 years, the BA
should be held to the DCS for that contingency. o Due to concerns we have in BAL013, we believe the reporting form for BAL-002 should also have a reporting slot for
large loss of load events (Order No. 693 directive), but for reasons we state in BAL013, believe that these should be excluded from compliance evaluation. Also BAL001’s RBC is a more effective way to meet the FERC directive for loss of load events.
o The continent-wide contingency reserve policy should be a separate guidance
document under the purview of the NERC Operating Committee with comments
collected under the standards process along with this standard. This meets the 693
directive. The policy document should provide guidance on how the BA should assess
the necessary amount of reserves as well as provide simple definitions of the
different types of reserves. Once these terms are defined and commented on by the
Industry in the policy, NERC should add these four types of reserves to “Attachment
1-TOP-005 Electric System Reliability Data” with the expectation in the policy that

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Yes or No

Yes or No

Reliability Coordinators collect this information in real time for use in the EEA
process. The policy could ask the BAs to initially review and assess their needs and
relay this to their RC. The policy would be available for re-review if the BA’s
performance approaches non-compliance. o The standard should be based on the
lesser of 80% of MSSC, 1000MW, or a lower value chosen by the Balancing Authority.

Question 10 Comment

IRC-SRC

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

10
2

Besides the concerns presented above, we are troubled with the significant changes
that will occur within R1 compared to today’s DCS and the fact that the drafting team
is asking no questions about those changes. The current DCS is measured on a
quarterly basis. The way the proposed requirement 1 and VSL is crafted, this is now
an event by event compliance evaluation. When you add the fact that the team is
also embedding a 500 MW reporting threshold and the multi-contingent event
expectation, this exposes the industry to a heavy-handed standard for no reliability
need. It should be noted that DCS performance has been stellar across North

1. The BARC SDT has modified the standard to provide for the reporting threshold to be on an Interconnection by
Interconnection basis.
2. The SDT has preserved the two requirements that you have identified within Requirement R1 and R2. In addition, the
proposed Requirement R2 preserves the existing requirement to maintain reserve equal to MSSC (present Requirement R3.1).
3. This standard is designed to measure performance of your contingency reserve for Balancing Contingency Events up to your
MSSC. This does not relieve you from meeting all of the other NERC reliability standards during these events. While the SDT
understands your concern about single contingencies greater than MSSC, the SDT has chosen to use a single pre-determined
contingency as the basis for this standard since it is well defined within the industry.
4. The SDT agrees with the industry with regards to the need for BAL-013-1. The SDT has chosen to stop development on a Large
Loss of Load standard (BAL-013-1) and believes that the loss of a large load is covered in BAL-001-2 Requirement R2 (BAAL).
5. The SDT is developing a Reserve Guideline for approval and posting by the NERC OC.
6. The SDT considered using the approach of BAAL as the basis for performance but chose the present method since concerns
other than frequency performance may need to be addressed. There is also a compelling interest in measuring the adequacy
of reserve.

Response: Thank for your comments.

Organization

Organization

Question 10 Comment

10
3

America compared to what existed under Policy 1. The changes being implemented
are well beyond what was in the drafting team’s SAR and the Order No. 693
directives.The SAR for the drafting team was basically to clean up the V0 clutter in the
standard and address Order No 693 directives. The only two true requirements in
the V0 standard are to recover from reportable events in 15 minutes and replenish
reserves within 90 minutes. These should be the basis of BAL-002-1. Our
recommendation are: o Preserve the two true requirements today (recover from
reportable events within 15 minutes and replenish reserves in 90 minutes). o
Provide clarity in the compliance section of the standard or the background
document how events > MSSC are reported. Note: We believe it is acceptable to put
something in the compliance section of the standard that notes if the same event >
than MSSC occurs within 3 years, the BA should be held to the DCS for that
contingency. o Due to concerns we have in BAL-013, we believe the reporting form
for BAL-002 should also have a reporting slot for large loss of load events (Order No.
693 directive), but for reasons we state in BAL-013, believe that these should be
excluded from compliance evaluation. o The continent-wide contingency reserve
policy should be a separate guidance document under the purview of the NERC
Operating Committee with comments collected under the standards process along
with this standard. This meets the 693 directive. The policy document should
provide guidance on how the BA should assess the necessary amount of reserves as
well as provide simple definitions of the different types of reserves. Once these terms
are defined and commented on by the Industry in the policy, NERC should add these
four types of reserves to “Attachment 1-TOP-005 Electric System Reliability Data”
with the expectation in the policy that Reliability Coordinators collect this
information in real time for use in the EEA process. The policy could ask the BAs to
initially review and assess their needs and relay this to their RC. The policy would be
available for re-review if the BA’s performance approaches non-compliance. o The
standard should be based on the lesser of 80% of MSSC, 1000MW, or a lower value
chosen by the Balancing Authority.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Yes or No

Yes or No

Question 10 Comment

ERCOT

10
4

ERCOT ISO supports the intention of the standard BAL-002-2 R1 to restore ACE back
to pre-disturbance ACE but not necessarily to zero or the pre-disturbance ACE. The
ACE recovery goal should be pre-disturbance levels. Therefore, ERCOT suggests the
SDT establish a (epsilon1*Frequency Bias*10) band around the pre-disturbance ACE
or zero ACE, and, if during recovery ACE is recovered within this range, entities would
be compliant. This structure of establishing a goal, but providing for a compliance
"floor" based upon the proposed range, will achieve the desired reliability benefits
while also providing a reasonable degree of flexibility for circumstances where
recovery to the exact pre-disturbance level is difficult to achieve, and unnecessary to

BPA is in support of this standard.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Response: Thank you for your support.

Bonneville Power
Administration

1. The BARC SDT has modified the standard to provide for the reporting threshold to be on an Interconnection by
Interconnection basis.
2. The SDT has preserved the two requirements that you have identified within Requirement R1 and R2. In addition, the
proposed Requirement R2 preserves the existing requirement to maintain reserve equal to MSSC (present Requirement R3.1).
3. This standard is designed to measure performance of your contingency reserve for Balancing Contingency Events up to your
MSSC. This does not relieve you from meeting all of the other NERC reliability standards during these events. While the SDT
understands your concern about single contingencies greater than MSSC, the SDT has chosen to use a single pre-determined
contingency as the basis for this standard since it is well defined within the industry.
4. The SDT agrees with the industry with regards to the need for BAL-013-1. The SDT has chosen to stop development on a Large
Loss of Load standard (BAL-013-1) and believes that the loss of a large load is covered in BAL-001-2 Requirement R2 (BAAL).
5. The SDT is developing a Reserve Guideline for approval and posting by the NERC OC.
6. The SDT considered using the approach of BAAL as the basis for performance but chose the present method since concerns
other than frequency performance may need to be addressed. There is also a compelling interest in measuring the adequacy
of reserve.

Response: Thank for your comments.

Organization

Yes or No

Question 10 Comment

ERCOT ISO is voting "yes", but has reservations as described above and requests that
the SDT revise the standard accordingly.

ERCOT ISO also suggests that the 500 MW threshold be removed from the definition
of Reportable Balancing Contingency Event. This requirement would impose an
undue burden. There is no reliability reason to require mandatory reporting for these
smaller events. It will merely create an administrative obligation with no
corresponding reliability benefits. For instance, currently ERCOT ISO would typically
need to report less than five events annually, but this new standard would increase
this reporting burden to over 50 each year (based upon 2012 disturbances), without
any corresponding reliability benefits. Accordingly, this obligation should be
removed.If the SDT elects not to remove the 500 MW threshold generally, ERCOT ISO
suggests that the threshold be removed for single-BA Interconnections. The
threshold for single-BA Interconnections should be established as 80 percent of the
MSSC.

ensure reliability.

Have the option also calculate ACE using the following formula: ACE = (NIA − NIS) −
10B (FA − FS) - IME

Avista

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

10
5

I can support this draft standard with the clarifications requested in Question #1
above.

Response: Thank you for your comment. In response to your concern, the SDT has modified the definition.

NextEra Energy

The BARC SDT has modified the standard to provide for the reporting threshold to be on an Interconnection by Interconnection
basis.

In response to your concern, the SDT has modified Requirement R1.

Response: Thank you for your comment.

Organization

Yes or No

Question 10 Comment

Taking a conditional-based approach across multiple standards does not serve the
reliability of the bulk electric system, as it takes a straightforward concept, overly
complicates it, and distracts Real Time Operators from the core reliability objectives.

In addition, the definitions for Contingency Event Recovery Period and Contingency
Reserve Restoration Period are quite similar and would most likely prove confusing to
industry in their application.

The definition for, and application of, Contingency Event Recovery Period is
unnecessarily complex, confusing, and likely unpractical in its application. For
example, if a unit was taken out of service due to a controlled shut-down, the Real
Time Operator’s most pressing responsibility is balancing load and generation.
Requiring this person to use the proposed methodology to determine exactly the
contingency event recovery period began would distract the Real Time Operator from
their core balancing responsibilities. Rather than take this approach, we recommend
retaining the existing way of determining when the recovery period begins, which is a
more straightforward and reasonable approach.

AEP disagrees with the latest proposed definition of “Pre†Reportable Contingency
Event ACE Value”, which has been made ambiguous by the most recent
modifications. What is the intent of the drafting team in modifying the definition in
this way? If this definition were to be used, new tools would likely need to be
developed in order to calculate the value in this manner, as the operators would now
be required to continuously calculate the ACE value based on this new definition.

In addition to the comments provided to the earlier questions above, AEP offers the
following additional comments for consideration.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

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6

1 & 2 - The SDT had no intent of causing you to change how you determine your ACE today under the existing standard, however,

Response: Thank you for your comment.

American Electric Power

Response: Thanks you for your support. Please refer to our response to your comments for Question #1.

Organization

Yes or No

Question 10 Comment

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7

PJM appreciates the SDT’s goal of drafting a continent-wide standard but disagrees
with the SDT’s approach of ‘one size fits all’ in defining a Reportable Balancing
Contingency Event. As previously stated, PJM believes that the Commission directive
of defining a significant (frequency) event is not satisfied by this standard.
Additionally, using 500MW as an example, a loss of 500MW may cause a significant
frequency deviation at midnight on April 1st but not at 17:00 on August 1st. The same
500MW loss may cause a significant frequency deviation in the Western
Interconnection but not in the Eastern Interconnection. PJM believes that this SDT

(2) The “Applicability” section clearly states that the standard does not apply to
an RE under an EEA. Would it be sufficient for the RE to restore ACE to within
the dynamic BAAL limits instead of the “hard” criteria of zero or pre-contingent
ACE value within the 15 minute recovery period? Once an RE has gotten ACE
within the BAAL limit it is no longer burdening the interconnection - wouldn’t
this be a sufficient recovery? There should be coordination of the recovery
required under BAL-002 with performance under the BAL-001(BAAL) standard.

(1) An EEA in effect for any BA or RSG other than the RE experiencing the
contingency should not give the RE an exemption from R1. The language makes
the assumption that both the EEA and contingency are affecting a single,
specific RE - this is probably what the SDT intended but the language used in R1
and R2 is too generic.

In R1 and R2, delete the language related to a Responsible Entity under an Energy
Emergency Alert Level 2 or Level 3, for the following reasons:

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

PJM Interconnection, LLC

4 – The SDT does not understand your comment about “conditional based approach across multiple standards” and therefore
would need additional information to provide a response.

3 – The SDT created the definitions to provide additional clarity and flexibility for the BAs.

they intended to provide the necessary flexibility for you to account for prior and subsequent Balancing Contingency Events during
the defined period. In addition, the determination of the pre-contingent ACE was modified to be consistent with the direction of
BAL-003-1 and to eliminate possible inconsistency in its determination.

Organization

Yes or No

In BAL-003-1, that was recently approved by the industry and the NERC BOT, the FR
SDT identified different frequency excursion criteria for each Interconnection that are
used to identify candidate events for evaluating frequency response performance.
The FRI Report, approved by the NERC PC and accepted by the NERC OC, identified
different statistically derived delta frequencies for each Interconnection in
developing IFRO’s. The State of Reliability Report prepared annually by the NERC
identifies “the triggers for significant frequency events” that are specific to each
Interconnection (ALR1-12 Assessment). As previously stated, PJM respectfully
suggests that the SDT give due consideration to redefining a Reportable Balancing
Contingency Event that satisfies the Commission directive of defining a significant
(frequency) deviation. Such a definition could resemble 80% of MSSC or a supply,
load, or scheduling event that results in a frequency deviation of XXmHz (depending
on the Interconnection) in any rolling XX second period. Previous work completed by
the FR SDT and NERC staff could be leveraged to this end. PJM believes this is one
approach that could satisfy the directive set forth in Order 693.

In the proposed BAL-001-2, the BARC SDT proposes a definition of ACE that is only
applicable for the Western Interconnection.

and other SDT’s have acknowledged that a ‘one size fits all’ approach is not always
appropriate for all Interconnections.

Question 10 Comment

Portland General Eletric is supportive of this standard.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Portland General Electric
Company

3- The SDT has modified the definition for Reporting Ace addressing your concern.

10
8

2 & 4 – The BARC SDT has modified the standard to provide for the reporting threshold to be on an Interconnection by
Interconnection basis.

1 – The SDT understands your concern and has modified Requirement R1 and Requirement R2 accordingly.

Response: Thank you for your comment.

Organization

Yes or No

Provide flexibility for an RSG ACE to be calculated based on aggregate participants
frequency bias and RSG interchange with non-participants.

Question 10 Comment

2. Applicability Section - ReliabilityFirst recommends removing the paragraph stating
“Applicability is determined on an individual event basis...” from the Applicability
section. The Applicability section should state the functional entity that is required to
comply with the standard and the requirements should state any conditions
necessary to achieve the action or outcome.

1. Definition of Reportable Balancing Contingency Event: ReliabilityFirst does not
agree with the inclusion of last sentence (i.e., The 80% threshold may be reduced
upon written notification to the Regional Entity) within the definition. As written, the
definition infers that there is an expectation that a Regional Entity may have to make
a determination on whether to accept a reduction in the 80% threshold based upon
the written notification. This is troublesome in two ways. One, this is written more
like a requirement, though it is actually contained within a definition. Two, standards
should not be written with expectation placed upon a non-registered entity (i.e., the
Regional Entity). ReliabilityFirst recommends removing this last sentence and any
reference to the Regional Entity.

ReliabilityFirst votes in the negative for this standards and offers the following for
consideration:

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

10
9

2 – The individual event basis was included to allow for the flexibility for individual BAs participating in a Reserve Sharing Group

1 – The definition does not put a requirement on the Regional Entity. The definition simply requires the Regional Entity to be
notified.

Response: Thank you for your comment.

ReliabilityFirst

Response: Thank you for your comment. The SDT has modified the definition to address your comment.

Seminole Electric Cooperative,
Inc.

Response: Thank you for your support.

Organization

Yes or No

Question 10 Comment

Remove the 500 MW threshold in the definition of Reportable Balancing Contingency
Event

Seattle City Light supports the general concepts of this draft of BAL-002-2, but as with
BAL-001-2, Seattle thinks this draft needs more work and should not be implemented
as currently written. It appears to have been rushed. Several specific
recommendations for changes have been noted above. However, at least until the
Guidelines document is available that details how this Standard will work in
conjunction with other BAL Standards, Seattle cannot support this draft.

11
0

In addition, the VSLs are very confusing. All levels state that the Responsible Entity
recovered from the event, yet they recovered to less than 100% of the required
recovery. How can it be “recovered” without reaching 100%? Instead, we suggest
that the VSLs recognize that the Responsible Entity “partially recovered” from the
event.

Tacoma Power appreciates the opportunity to provide comments. We cannot
support this draft of the standard because we are unfamiliar with the phrase, “...
known load used as a resource ...” in the definition of a Balancing Contingency Event.
Therefore, this phrase must be defined or replaced so that there is no confusion
within the industry and compliance authorities. We suggest using the phrase, “...
interruptible load claimed as available reserves ...,” which is Tacoma Power’s
interpretation.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Tacoma Power

Response: Thank you for your comment. The SDT is presently working on the Reserve Policy Guideline document. The SDT will be
presenting the draft Guideline document to the NERC OC for their acceptance at their September 2013 meeting.

seattle city light

Response: Thank you for your comment. The BARC SDT has modified the standard to provide for the reporting threshold to be on
an Interconnection by Interconnection basis.

Oklahoma Gas & Electric

but opting out of the group for an individual event basis in accordance with the respective Reserve Sharing Group agreement.

Organization

Yes or No

Question 10 Comment

11
1

I would strongly suggest that the wording for Requirement 1 should be modified to
read as follows:R1. Except when an Energy Emergency Alert Level 2 or Level 3 is in
effect, the ResponsibleEntity experiencing a Reportable Balancing Contingency Event
shall demonstrate thatwithin the Contingency Event Recovery Period the Responsible
Entity returned its Reportable ACEto: [Violation Risk Factor: Medium][Time Horizon:
Real†time Operations] Zero, (if its Pre†Reportable Contingency Event ACE
Value was positive or equal tozero):o less the sum of the magnitudes of all
subsequent Balancing ContingencyEvents that occur prior to that value of Reportable
ACE within the Contingency Event Recovery Period, ando Further reduced by the
magnitude of the difference between (i) theResponsible Entity’s Most Severe Single
Contingency (MSSC) and (ii) the sumof the magnitudes of the Reportable Balancing
Contingency Event and allprevious Balancing Contingency Events that have not
completed theirContingency Event Restoration Period when the sum referenced in
clause (ii)of this bullet is greater than MSSC,Or, Its Pre†Reportable Contingency
Event ACE Value, (if its Pre†ReportableContingency Event ACE Value was
negative),o less the sum of the magnitudes of all subsequent Balancing
ContingencyEvents that occur prior to that value of Reportable ACE within the
Contingency Event Recovery Period, ando Further reduced by the magnitude of the
difference between (i) theResponsible Entity’s Most Severe Single Contingency
(MSSC) and (ii) the sumof the magnitudes of the Reportable Balancing Contingency
Event and allprevious Balancing Contingency Events that have not completed

The definition of "Pre-reportable Contingency Event ACE Value" should be modified
as follows:The term "ACE" should be replaced by the term "Reportable ACE"
wherever it is used in this definition. "ACE" is not adequately defined while
"Reportable ACE" is.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Energy Mark, Inc.

The SDT has modified the VSLs for Requirement R1 based on comments from the industry.

The SDT has modified the definition to address concerns from the industry.

Response: Thank you for your comment.

Organization

Yes or No
theirContingency Event Restoration Period when the sum referenced in clause (ii)of
this bullet is greater than MSSC.

Question 10 Comment

The drafting team is proposing to continue to use only ACE under Requirement R1 as
the measure of reliability in the determination of Balancing Authority or RSG
compliance. As has been seen in actual operation, the current methodology can lead
to and has caused RC directives to drop load when there was not a reliability issue,
defined as a frequency concern or transmission line loading issue. ACE is not a
primary measure of reliability, only equity. Therefore, Xcel Energy is voting against
the proposed standard. To remedy this deficiency in the proposed standard, the
drafting team should utilize the BAAL limit as a more appropriate measure of
response to the sudden loss of generation, not pre-event ACE or zero, whichever is
lower. As proposed by Xcel Energy, this does not do away with DCS as originally
proposed under BAAL but would change the measure of compliance in the DCS
process to a more appropriate, reliability based measure. Xcel Energy is also not
proposing to change the 15-minute period in BAL-002 for a reportable event with this
modification.

11
2

With respect to the proposed definitions, it is not clear why the SDT modified each of
the proposed definitions but is only requesting input on a subset of the defined terms

The PPL NERC Registered Affiliates offer the following comments:

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

PPL NERC Registered Affiliates

Response: Thank you for your comment. The SDT considered using the approach of BAAL as the basis for performance but chose
the present method since concerns other than frequency performance may need to be addressed. There is also a compelling
interest in measuring the adequacy of reserve. The issue you have raised is outside the scope of this standard and should be
resolved when IRO-005-4 is approved by FERC.

Xcel Energy

The SDT has modified Requirement R1 to address your comment.

The SDT has modified the definition of Reporting ACE based on comments from the industry.

Response: Thank you for your comment.

Organization

Organization

Question 10 Comment

11
3

With respect to R2, it is not clear if responsible entity experiencing a non-reportable
Balancing Contingency Event (i.e. a loss less than 500MW) is expected to maintain

Also, we suggest it would be more appropriate for the Responsible Entity to restore
ACE to within the BAAL limits rather than the “hard” zero or pre-contingent ACE value
within the 15 minute recovery period. Once a responsible entity has restored ACE
within the BAAL limits it is no longer burdening the interconnection - this would be a
sufficient recovery.We suggest that a successful response by the responsible entity
would return ACE to the lesser of 0 or its real time BAAL limit (if its Pre-Reportable
Contingency Event ACE was positive or equal to zero) and similarly - ACE returned to
the lesser of its Pre-Reportable Contingency ACE Value or BAAL limit (if its PreReportable Contingency Event ACE was negative).

2) The Applicability section clearly states that the standard does not apply to a
responsible entity under an EEA. If the SDT intends to include the exemption in
the requirement language, it is suggest R1 is revised as follows: “Except when
an Energy Emergency Alert Level 2 or Level 3 has been requested by the
Responsible Entity, the Responsible Entity experiencing a Reportable ...” .

1) An EEA in effect for any BA or RSG other than the responsible entity
experiencing the contingency should not give the responsible entity an
exemption from R1. For example, an EEA in effect for a BA in Florida should not
be a consideration for the performance of a contingent responsible entity
anywhere in the eastern interconnection. The language makes the assumption
that both the EEA and contingency are affecting a single, specific responsible
entity - if this is what the SDT intended, the language as currently written is too
generic.

With respect to requirement 1, it is suggested that the phrase “Except when an
Energy Emergency Alert Level 2 or Level 3 is in effect,” be deleted for the following
reasons:

during this comment period.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Yes or No

Yes or No

Requirement 2 (along with the currently effective version 1 of BAL-002) uses a
capitalized term “Disturbance Recovery Period” that is not in the NERC Glossary of
Terms. The SDT may have intended to use the term Contingency Event Recovery
Period in lieu of Disturbance Recovery Period in requirement 2.

With respect to measurement M2, it is not clear if Contingency Reserves may fall
below MSSC for the first 105 minutes (Contingency Event Recovery Period plus
Contingency Reserve Restoration Period) following any deployment of Contingency
Reserves. If so, this may resolve the current expectation as written in R2. However,
measures are not requirements and therefore, compliance is not judged through any
potential flexibility provided in M2 or the VSLs.

Contingency Reserves at least equal to its MSSC. As currently written, it appears that
R2 could require a Responsible Entity to always carry Contingency Reserves equal or
greater than its MSSC plus 500MW (or its reportable threshold) so that Contingency
Reserves will always exceed MSSC.

Question 10 Comment

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

6 – The SDT has made the necessary correction for the error you identified.

11
4

4 – The SDT has modified Requirement R2 in response to concerns raised by the industry.
5 – An entity may deploy contingency reserve for any Balancing Contingency Event whether the event is reportable or not which
provides you 105 minutes to restore your reserve.

3 - The SDT considered using the approach of BAAL as the basis for performance but chose the present method since concerns
other than frequency performance may need to be addressed. There is also a compelling interest in measuring the adequacy of
reserve.

2 – The SDT understands your concern and has modified Requirement R1 and Requirement R2 accordingly.

1 – The SDT only asked questions when it made a significant modification. The SDT was not precluding anyone from providing a
comment on any part of the standard through Question #10.

Response: Thank you for your comment.

Organization

Yes or No

o If the contingency event is greater than MSSC, further reduce the ACE recovery
magnitude by difference between the Responsible Entity’s MSSC and the
uncompleted Balancing Contingency Events’ magnitude summation.

o less the Balancing Contingency Events’ magnitude summation for all subsequent
events occurring within the Contingency Event Recovery Period, and

o Its Pre†Reportable Contingency Event ACE, (if its Pre†Reportable Contingency
Event ACE was negative),

2. While I think I understand the goal of R1, to return ACE to zero neglecting other
contingency events within the recovery period, the wording is very confusing. Expect
misapplication of the standard with the existing wording. I suggest, for bullet #2:

The Reportable Balancing Contingency Event definition lacks clarity. Are we to choose
the higher of 500 MW vs. 80% of the MSSC or the lower of 500 MW vs. 80% of the
MSSC? Seems like the measurement should be the higher of the two.

Question 10 Comment

11
5

The wording of the recovery target ACE in Requirement 1 needs to be replaced as
follows: "less the sum of the magnitudes of all subsequent Balancing Contingency
Events that occur WITHIN THE CONTINGENCY EVENT RECOVERY PERIOD [caps mine]"
should be replaced by "less the sum of the magnitudes of all subsequent Balancing
Contingency Events that occur AT THE MOMENT OF RECOVERY (OR NEARESTRECOVERY), or beforehand [caps mine]". Otherwise, by containing the word "all" in
the selected wording, R1 sanctions a BA's avoiding non-compliance due to insufficient
reserve, by incurring a subsequent contingency within the recovery period to reduce

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Keen Resources Ltd.

The individual event basis was included to allow for the flexibility for individual BAs participating in a Reserve Sharing Group but
opting out of the group for an individual event basis in accordance with the respective Reserve Sharing Group agreement.

The reporting threshold would be the lower of either 80% of MSSC or the interconnection threshold.

Response: Thank you for your comment.

NV Energy

Organization

Yes or No

Furthermore, the current R1 definition contradicts the definition of "Best ACE"
contained in the Background Document that was intended to preempt such BA
behavior by defining "Best ACE" as: the "most positive ACE during the Contingency
Event Recovery Period occurring after the last subsequent event, if any (MW)". The
meaning of "if any" is specified only in the attached spreadsheet that makes
"claiming" such a subsequent event "optional" to the BA. In other words, a BA will
not claim a subsequent event that makes the BA's compliance worse. A clearer
alternative definition of "Best ACE", that does not require the "optionality" obscurely
lodged in the spreadsheet and that would harmonize with the needed change to the
R1 wording, would be "the least negative value if there are no positive values, or the
most positive value of any positive values, among the values of ACE occurring during
the recovery period, unless it is the ACE to which the addition of any subsequent
events that occurred prior to or concurrently with it results in a value that is the least
negative value if there are no positive values, or the most positive value of any
positive values, among all such resultant values and the other ACE values during the
recovery period.”

the BA's recovery requirement.

Question 10 Comment

11
6

There is an embedded expectation to recover from and measure multi-contingent
events beyond MSSC. When these events happen, something bigger is going on.
Transmission security is probably an issue. Forcing a knee-jerk expectation to drive
ACE back toward zero during a major event will likely do more harm than good. This
is another thing that wasn’t in the drafting team’s SAR or in a directive. Events
greater than MSSC should be reported, but not evaluated for compliance. While it’s

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

SERC OC Standards Review
Group

The SDT discussed your proposed method during the drafting of the standard but chose to not pursue this due to the complexities
involved.

The SDT understands your concern and has made modifications to Requirement R1 based on comments from the industry.

Response: Thank you for your comment.

Organization

Organization

Question 10 Comment

11
7

In R1 and R2, delete the language related to an RE under an Energy Emergency Alert

In the proposed BAL-001-2, the BARC SDT proposes a definition of ACE that is only
applicable for the Western Interconnection. In BAL-003-1, that was recently approved
by the industry and the NERC BOT, the FR SDT identified different frequency
excursion criteria for each Interconnection that are used to identify candidate events
for evaluating frequency response performance. The FRI Report, approved by the
NERC PC and accepted by the NERC OC, identified different statistically derived delta
frequencies for each Interconnection in developing IFRO’s. The State of Reliability
Report prepared by the NERC identifies “the triggers for significant frequency events”
that are specific to each Interconnection.We respectfully suggest that the SDT give
due consideration to redefining a Balancing Contingency Event and Reportable
Balancing Contingency Event that satisfies the Commission directive of defining a
significant (frequency) deviation. Such a definition could resemble 80% of MSSC or a
supply, load, or scheduling event that results in a frequency deviation of XXmHz
(depending on the Interconnection) in any rolling XX second period. Previous work
completed by the FR SDT and NERC staff could be leveraged to this end. We believe
this is one approach that could satisfy the directive set forth in Order 693.

We appreciate the SDT’s goal of drafting a continent-wide standard but disagree
with the SDT’s approach of ‘one size fits all’ in defining a Reportable Balancing
Contingency Event. As previously stated, we believe that the Commission directive of
defining a significant (frequency) event is not satisfied by this standard. Additionally,
using 500 MW as an example, a loss of 500 MW may cause a significant frequency
deviation at midnight on April 1st but not at 17:00 on August 1st. The same 500 MW
loss may cause a significant frequency deviation in the Western Interconnection but
not in the Eastern Interconnection. We believe that this SDT and other SDT’s have
acknowledged that a ‘one size fits all’ approach is not always appropriate for all
Interconnections.

fine to embed some of the calculations in the background document in a reporting
form, events greater than MSSC should be excluded from compliance evaluation.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Yes or No

Organization

Question 10 Comment

11
8

These comments were also supporteed by Ron Carlsen with Southern Company. The
comments expressed herein represent a consensus of the views of the above named
members of the SERC OC Standards Review Group only and should not be construed

Would it be sufficient for the RE to restore ACE to within the dynamic BAAL limits
instead of the “hard” criteria of zero or pre-contingent ACE value within the 15
minute recovery period? Once an RE has gotten ACE within the BAAL limit it is no
longer burdening the interconnection - wouldn’t this be a sufficient recovery? There
should be coordination of the recovery required under BAL-002 with performance
under the BAL-001(BAAL) standard. We suggest that a successful response by the RE
would return ACE to the lesser of 0 or its real time BAAL low limit (if its PreReportable Contingency Event ACE was positive or equal to zero) and similarly - ACE
returned to the lesser of its Pre-Reportable Contingency ACE Value or BAAL low limit
(if its Pre-Reportable Contingency Event ACE was negative). If the interconnection
frequency is high - why require a BA to increase generation more than is necessary to
meet its BAAL low limit? If interconnection frequency is low, the BAAL low limit as
well as the zero or pre-contingent ACE rule would still apply.

(2) The “Applicability” section clearly states that the standard does not apply to
an RE under an EEA. Words could be added to R1 and R2 to clarify that the
contingent RE is also the RE experiencing an EEA but a better solution is to
simply delete the EEA related language from R1 and R2,

(1) An EEA in effect for any BA or RSG other than the RE experiencing the
contingency should not give the RE an exemption from R1. E.g. an EEA in effect
for a BA in Florida should not be a consideration for the performance of a
contingent RE anywhere in the EI. The language makes the assumption that
both the EEA and contingency are affecting a single, specific RE - this is
probably what the SDT intended but the language used in R1 and R2 is too
generic.

Level 2 or Level 3, for 2 reasons:

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Yes or No

Yes or No
as the position of the SERC Reliability Corporation, or its board or its officers.

Question 10 Comment

11
9

There is an embedded expectation to recover from and measure multi-contingent
events beyond MSSC. When these events happen, something bigger is going on.
Transmission security is probably an issue. Forcing a knee-jerk expectation to drive
ACE back toward zero during a major event will likely do more harm than good. This
is another thing that wasn’t in the drafting team’s SAR or in a directive. Events
greater than MSSC should be reported but not evaluated for compliance. While it’s
fine to embed some of the calculations in the background document in a reporting
form, events greater than MSSC should be excluded from compliance evaluation. We
appreciate the SDT’s goal of drafting a continent-wide standard but disagree with the
SDT’s approach of ‘one size fits all’ in defining a Reportable Balancing Contingency
Event. As previously stated, we believe that the Commission directive of defining a
significant (frequency) event is not satisfied by this standard. Additionally, using 500
MW as an example, a loss of 500 MW may cause a significant frequency deviation at
midnight on April 1st but not at 17:00 on August 1st. The same 500 MW loss may
cause a significant frequency deviation in the Western Interconnection but not in the
Eastern Interconnection. We believe that this SDT and other SDT’s have
acknowledged that a ‘one size fits all’ approach is not always appropriate for all

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

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

5 - The SDT considered using the approach of BAAL as the basis for performance but chose the present method since concerns
other than frequency performance may need to be addressed. There is also a compelling interest in measuring the adequacy of
reserve.

4 - The SDT understands your concern and has modified Requirement R1 and Requirement R2 accordingly.

2 & 3 – The BARC SDT has modified the standard to provide for the reporting threshold to be on an Interconnection by
Interconnection basis.

1 – The SDT modified the existing standard by eliminating administrative requirements, however. they have maintained
requirements associated with performance and addressed the FERC directive in order 693.

Response: Thank you for your comment.

Organization

Organization

Question 10 Comment

12
0

Interconnections. In the proposed BAL-001-2, the BARC SDT proposes a definition of
ACE that is only applicable for the Western Interconnection. In BAL-003-1, that was
recently approved by the industry and the NERC BOT, the FR SDT identified different
frequency excursion criteria for each Interconnection that are used to identify
candidate events for evaluating frequency response performance. The FRI Report,
approved by the NERC PC and accepted by the NERC OC, identified different
statistically derived delta frequencies for each Interconnection in developing IFRO’s.
The State of Reliability Report prepared by the NERC identifies “the triggers for
significant frequency events” that are specific to each Interconnection.We
respectfully suggest that the SDT give due consideration to redefining a Balancing
Contingency Event and Reportable Balancing Contingency Event that satisfies the
Commission directive of defining a significant (frequency) deviation. Such a definition
could resemble 80% of MSSC or a supply, load, or scheduling event that results in a
frequency deviation of XXmHz (depending on the Interconnection) in any rolling XX
second period. Previous work completed by the FR SDT and NERC staff could be
leveraged to this end. We believe this is one approach that could satisfy the directive
set forth in Order 693.In R1 and R2, delete the language related to an RE under an
Energy Emergency Alert Level 2 or Level 3, for 2 reasons: (1) An EEA in effect for any
BA or RSG other than the RE experiencing the contingency should not give the RE an
exemption from R1. E.g. an EEA in effect for a BA in Florida should not be a
consideration for the performance of a contingent RE anywhere in the EI. The
language makes the assumption that both the EEA and contingency are affecting a
single, specific RE - this is probably what the SDT intended but the language used in
R1 and R2 is too generic. (2) The “Applicability” section clearly states that the
standard does not apply to an RE under an EEA. Words could be added to R1 and R2
to clarify that the contingent RE is also the RE experiencing an EEA but a better
solution is to simply delete the EEA related language from R1 and R2,Would it be
sufficient for the RE to restore ACE to within the dynamic BAAL limits instead of the
“hard” criteria of zero or pre-contingent ACE value within the 15 minute recovery
period? Once an RE has gotten ACE within the BAAL limit it is no longer burdening

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Yes or No

Yes or No

the interconnection - wouldn’t this be a sufficient recovery? There should be
coordination of the recovery required under BAL-002 with performance under the
BAL-001(BAAL) standard. We suggest that a successful response by the RE would
return ACE to the lesser of 0 or its real time BAAL low limit (if its Pre-Reportable
Contingency Event ACE was positive or equal to zero) and similarly - ACE returned to
the lesser of its Pre-Reportable Contingency ACE Value or BAAL low limit (if its PreReportable Contingency Event ACE was negative). If the interconnection frequency is
high - why require a BA to increase generation more than is necessary to meet its
BAAL low limit? If interconnection frequency is low, the BAAL low limit as well as the
zero or pre-contingent ACE rule would still apply.

Question 10 Comment

12
1

The Standard can be simplified by replacing the existing requirements with ones that
read: o recover from a Reportable Event within 15 minutes; o replenish reserves
within 90 minutes.

There isn’t an appropriate technical justification for requiring a 500 MW threshold. If
the justification is simply to obtain more data samples, a 1600 data request is more
appropriate than an enforceable Standard. Suggest reverting back to the 80%
threshold which has thus far, shown to provide for an adequate level of reliability.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Northeast Power Coodinating
Council

5 - The SDT considered using the approach of BAAL as the basis for performance but chose the present method since concerns
other than frequency performance may need to be addressed. There is also a compelling interest in measuring the adequacy of
reserve.

4 - The SDT understands your concern and has modified Requirement R1 and Requirement R2 accordingly.

2 & 3 – The BARC SDT has modified the standard to provide for the reporting threshold to be on an Interconnection by
Interconnection basis.

1 – The SDT modified the existing standard by eliminating administrative requirements however we have maintained
requirements associated with performance and addressed the FERC directive in order 693.

Response: : Thank you for your comment.

Organization

Yes or No

Question 10 Comment

There isn’t an appropriate technical justification for requiring a 500 MW threshold. If
the justification is simply to obtain more data samples, a 1600 data request is more
appropriate than an enforceable Standard. Suggest reverting back to the 80%
threshold which has thus far, shown to provide for an adequate level of reliability.The
Standard can be simplified by replacing the existing requirements with ones that
read: o recover from a Reportable Event within 15 minutes; o replenish reserves
within 90 minutes.As written, the Standard is overly complex.

12
2

We will support this standard, however please note the concerns expressed under Q2
and Q3, above, namely:

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

Independent Electricity
System Operator

Requirement R2 provides for recovery of reserves within 90 minutes. The additional qualifications allow for flexibility to address
unusual circumstances that can arise.

At the core Requirement R1 does require recovery in 15 minutes. The additional qualifications allow for flexibility to address
unusual circumstance that can arise.

The BARC SDT has modified the standard to provide for the reporting threshold to be on an Interconnection by Interconnection
basis. In addition, the SDT is attempting to respond to the FERC directive to identify those events that can have a significant
impact on frequency.

Response: Thank you for your comment.

ISO New England Inc.

Requirement R2 provides for recovery of reserves within 90 minutes. The additional qualifications allow for flexibility to address
unusual circumstances that can arise.

At the core Requirement R1 does require recovery in 15 minutes. The additional qualifications allow for flexibility to address
unusual circumstance that can arise.

The BARC SDT has modified the standard to provide for the reporting threshold to be on an Interconnection by Interconnection
basis. In addition, the SDT is attempting to respond to the FERC directive to identify those events that can have a significant
impact on frequency.

Response: Thank you for your comment.

Organization

Yes or No

b. The need to define the term Reserve Sharing Group Reporting ACE (or the lack of
explicit requirement for RSG to meet the DCS requirement).

a. The last sentence in the definition for Contingency Reserve, and

Question 10 Comment

While we appreciate the work done since previous versions of the project, and
recognize the clarity gained by eliminating reference to Balancing Contingency Events
with a future impact to ACE, we feel that additional confusion has been inserted by
the sub-points of R1. Given that the recovery requirement is a relatively short timeframe, the ability to quickly determine the recovery obligation is critical to the ability
to ensure compliance. We appreciate that the drafting team is attempting to
accommodate the notion that a prior Balancing Contingency Event might impact any
future events, but the methodology given for determining the recovery threshold is
overly complex, and represents a significant barrier to a system operator's ability to
interpret the requirement in Real Time and respond appropriately.

Consideration of Comments: Project 2010-14.1 BAL-002-2
Posted:

END OF REPORT

12
3

Response: Thank you for your comment. The present BAL-002 has 16 requirements and sub-requirements. The SDT has reduced
this down to two requirements, recover from a reportable event and ensure you have reserves.

Exelon

Response: Thank you for your comment and support. Please refer to our response to your comments on Questions 2 and 3.

Organization

Standards Announcement

Project 2010-14.1 Phase 1 of Balancing Authority Reliability-based
Controls: Reserves (BAL-001-2, BAL-002-2 and BAL-013-1)
Just a reminder…
Initial Ballot and Non-Binding Poll is now open through 8 p.m. Eastern April 25, 2013
Now Available

Initial ballots of the following three standards and non-binding polls of the associated Violation Risk
Factors (VRSs) and Violation Severity Levels (VSLs) for Phase 1 of Balancing Authority Reliability-based
Controls: Reserves is open through 8 p.m. Eastern on Thursday, April 25, 2013:
BAL-001-2- Real Power Balancing Control Performance
BAL-002-2- Contingency Reserve for Recovery from a Balancing Contingency Event
BAL-013-1- Large Loss of Load Performance
Background information for this project can be found on the project page.
Instructions

Members of the ballot pools associated with this project may log in and submit their vote for the
standards and opinion in the non-binding polls of the associated VRFs and VSLs by clicking here.
Next Steps

The ballot results will be announced and posted on the project page. The drafting team will consider
all comments received during the formal comment period and, if needed, make revisions to the
standard. If the comments do not show the need for significant revisions, the standard will proceed to
a recirculation ballot.
Standards Development Process

The Standards Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement

Project 2010-14.1 Phase 1 of Balancing Authority Reliability-based Controls:
Reserves
BAL-001-2, BAL-002-2 and BAL-013-1
Initial Ballot and Non-Binding Poll Results
Now Available
Initial ballots for the following three standards and non-binding polls of the associated VRFs and VSLs
in Phase 1 of Balancing Authority Reliability-based Controls: Reserves concluded at 8 p.m. Eastern on
Thursday, April 25, 2013:
x
x
x

BAL-001-2- Real Power Balancing Control Performance
BAL-002-2- Contingency Reserve for Recovery from a Balancing Contingency Event
BAL-013-1- Large Loss of Load Performance

Voting statistics are listed below, and the Ballot Results page provides a link to the detailed results for
the initial ballots.
Standards
BAL-001-2
BAL-002-2
BAL-013-1

Approval

Non-binding Poll Results

Quorum: 88.60 %

Quorum: 86.02 %

Approval: 66.98 %

Supportive Opinions: 73.19 %

Quorum: 88.51 %

Quorum: 86.46 %

Approval: 42.75 %

Supportive Opinions: 43.96 %

Quorum: 88.51 %

Quorum: 86.42 %

Approval: 23.84 %

Supportive Opinions: 25.24 %

Background information for this project can be found on the project page.
Next Steps

The drafting team will consider all comments received during the formal comment period and, if
needed, make revisions to the standards. If the comments do not show the need for significant
revisions, the standards will proceed to a recirculation ballot.

Standards Development Process
The Standards Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Reliability Standards Analyst, 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 2010-14.1

2

NERC Standards



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ϭ͘ ZĞĐŝƌĐƵůĂƚŝŽŶĂůůŽƚ

:ƵůLJϮϬϭϯ

Ϯ͘ EZKdĂĚŽƉƚŝŽŶ͘

ƵŐƵƐƚϮϬϭϯ

>ͲϬϬϭͲϮ
:ƵůLJ͕ϮϬϭϯ



WĂŐĞϭŽĨϭϯ



^ƚĂŶĚĂƌĚ>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
ĞĨŝŶŝƚŝŽŶƐŽĨdĞƌŵƐhƐĞĚŝŶ^ƚĂŶĚĂƌĚ
dŚŝƐƐĞĐƚŝŽŶŝŶĐůƵĚĞƐĂůůŶĞǁůLJĚĞĨŝŶĞĚŽƌƌĞǀŝƐĞĚƚĞƌŵƐƵƐĞĚŝŶƚŚĞƉƌŽƉŽƐĞĚƐƚĂŶĚĂƌĚ͘dĞƌŵƐ
ĂůƌĞĂĚLJĚĞĨŝŶĞĚŝŶƚŚĞZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚƐ'ůŽƐƐĂƌLJŽĨdĞƌŵƐĂƌĞŶŽƚƌĞƉĞĂƚĞĚŚĞƌĞ͘EĞǁŽƌ
ƌĞǀŝƐĞĚĚĞĨŝŶŝƚŝŽŶƐůŝƐƚĞĚďĞůŽǁďĞĐŽŵĞĂƉƉƌŽǀĞĚǁŚĞŶƚŚĞƉƌŽƉŽƐĞĚƐƚĂŶĚĂƌĚŝƐĂƉƉƌŽǀĞĚ͘
tŚĞŶƚŚĞƐƚĂŶĚĂƌĚďĞĐŽŵĞƐĞĨĨĞĐƚŝǀĞ͕ƚŚĞƐĞĚĞĨŝŶĞĚƚĞƌŵƐǁŝůůďĞƌĞŵŽǀĞĚĨƌŽŵƚŚĞŝŶĚŝǀŝĚƵĂů
ƐƚĂŶĚĂƌĚĂŶĚĂĚĚĞĚƚŽƚŚĞ'ůŽƐƐĂƌLJ͘
ZĞŐƵůĂƚŝŽŶZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ͗ŐƌŽƵƉǁŚŽƐĞŵĞŵďĞƌƐĐŽŶƐŝƐƚŽĨƚǁŽŽƌŵŽƌĞĂůĂŶĐŝŶŐ
ƵƚŚŽƌŝƚŝĞƐƚŚĂƚĐŽůůĞĐƚŝǀĞůLJŵĂŝŶƚĂŝŶ͕ĂůůŽĐĂƚĞ͕ĂŶĚƐƵƉƉůLJƚŚĞZĞŐƵůĂƚŝŶŐZĞƐĞƌǀĞƌĞƋƵŝƌĞĚĨŽƌ
ĂůůŵĞŵďĞƌĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐƚŽƵƐĞŝŶŵĞĞƚŝŶŐĂƉƉůŝĐĂďůĞƌĞŐƵůĂƚŝŶŐƐƚĂŶĚĂƌĚƐ͘
ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉZĞƉŽƌƚŝŶŐ͗ƚĂŶLJŐŝǀĞŶƚŝŵĞŽĨŵĞĂƐƵƌĞŵĞŶƚĨŽƌƚŚĞĂƉƉůŝĐĂďůĞ
ZĞŐƵůĂƚŝŽŶZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ͕ƚŚĞĂůŐĞďƌĂŝĐƐƵŵŽĨƚŚĞZĞƉŽƌƚŝŶŐƐ;ŽƌĞƋƵŝǀĂůĞŶƚĂƐ
ĐĂůĐƵůĂƚĞĚĂƚƐƵĐŚƚŝŵĞŽĨŵĞĂƐƵƌĞŵĞŶƚͿŽĨƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐƉĂƌƚŝĐŝƉĂƚŝŶŐŝŶƚŚĞ
ZĞŐƵůĂƚŝŽŶZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉĂƚƚŚĞƚŝŵĞŽĨŵĞĂƐƵƌĞŵĞŶƚ͘
ZĞƉŽƌƚŝŶŐ͗dŚĞƐĐĂŶƌĂƚĞǀĂůƵĞƐŽĨĂĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛ƐƌĞĂŽŶƚƌŽůƌƌŽƌ;Ϳ
ŵĞĂƐƵƌĞĚŝŶDt͕ǁŚŝĐŚŝŶĐůƵĚĞƐƚŚĞĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛ƐEĞƚĐƚƵĂů
/ŶƚĞƌĐŚĂŶŐĞĂŶĚŝƚƐEĞƚ^ĐŚĞĚƵůĞĚ/ŶƚĞƌĐŚĂŶŐĞ͕ƉůƵƐŝƚƐ&ƌĞƋƵĞŶĐLJŝĂƐŽďůŝŐĂƚŝŽŶ͕ƉůƵƐĂŶLJ
ŬŶŽǁŶŵĞƚĞƌĞƌƌŽƌ͘/ŶƚŚĞtĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͕ZĞƉŽƌƚŝŶŐŝŶĐůƵĚĞƐƵƚŽŵĂƚŝĐdŝŵĞ
ƌƌŽƌŽƌƌĞĐƚŝŽŶ;dͿ͘
ZĞƉŽƌƚŝŶŐŝƐĐĂůĐƵůĂƚĞĚĂƐĨŽůůŽǁƐ͗


ZĞƉŽƌƚŝŶŐс;E/оE/^ͿоϭϬ;&о&^Ϳо/D
ZĞƉŽƌƚŝŶŐŝƐĐĂůĐƵůĂƚĞĚŝŶƚŚĞtĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶĂƐĨŽůůŽǁƐ͗



ZĞƉŽƌƚŝŶŐс;E/оE/^ͿоϭϬ;&о&^Ϳо/Dн/d


tŚĞƌĞ͗
E/;ĐƚƵĂůEĞƚ/ŶƚĞƌĐŚĂŶŐĞͿŝƐƚŚĞĂůŐĞďƌĂŝĐƐƵŵŽĨĂĐƚƵĂůŵĞŐĂǁĂƚƚƚƌĂŶƐĨĞƌƐĂĐƌŽƐƐĂůů
dŝĞ>ŝŶĞƐĂŶĚŝŶĐůƵĚĞƐWƐĞƵĚŽͲdŝĞƐ͘ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐĚŝƌĞĐƚůLJĐŽŶŶĞĐƚĞĚǀŝĂ
ĂƐLJŶĐŚƌŽŶŽƵƐƚŝĞƐƚŽĂŶŽƚŚĞƌ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶŵĂLJŝŶĐůƵĚĞŽƌĞdžĐůƵĚĞŵĞŐĂǁĂƚƚ
ƚƌĂŶƐĨĞƌƐŽŶƚŚŽƐĞdŝĞ>ŝŶĞƐŝŶƚŚĞŝƌĂĐƚƵĂůŝŶƚĞƌĐŚĂŶŐĞ͕ƉƌŽǀŝĚĞĚƚŚĞLJĂƌĞŝŵƉůĞŵĞŶƚĞĚ
ŝŶƚŚĞƐĂŵĞŵĂŶŶĞƌĨŽƌEĞƚ/ŶƚĞƌĐŚĂŶŐĞ^ĐŚĞĚƵůĞ͘
E/^;^ĐŚĞĚƵůĞĚEĞƚ/ŶƚĞƌĐŚĂŶŐĞͿŝƐƚŚĞĂůŐĞďƌĂŝĐƐƵŵŽĨĂůůƐĐŚĞĚƵůĞĚŵĞŐĂǁĂƚƚ
ƚƌĂŶƐĨĞƌƐ͕ŝŶĐůƵĚŝŶŐLJŶĂŵŝĐ^ĐŚĞĚƵůĞƐ͕ǁŝƚŚĂĚũĂĐĞŶƚĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐ͕ĂŶĚƚĂŬŝŶŐ
ŝŶƚŽĂĐĐŽƵŶƚƚŚĞĞĨĨĞĐƚƐŽĨƐĐŚĞĚƵůĞƌĂŵƉƐ͘ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐĚŝƌĞĐƚůLJĐŽŶŶĞĐƚĞĚǀŝĂ
ĂƐLJŶĐŚƌŽŶŽƵƐƚŝĞƐƚŽĂŶŽƚŚĞƌ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶŵĂLJŝŶĐůƵĚĞŽƌĞdžĐůƵĚĞŵĞŐĂǁĂƚƚ
ƚƌĂŶƐĨĞƌƐŽŶƚŚŽƐĞdŝĞ>ŝŶĞƐŝŶƚŚĞŝƌƐĐŚĞĚƵůĞĚ/ŶƚĞƌĐŚĂŶŐĞ͕ƉƌŽǀŝĚĞĚƚŚĞLJĂƌĞ
ŝŵƉůĞŵĞŶƚĞĚŝŶƚŚĞƐĂŵĞŵĂŶŶĞƌĨŽƌEĞƚ/ŶƚĞƌĐŚĂŶŐĞĐƚƵĂů͘
;&ƌĞƋƵĞŶĐLJŝĂƐ^ĞƚƚŝŶŐͿŝƐƚŚĞ&ƌĞƋƵĞŶĐLJŝĂƐ^ĞƚƚŝŶŐ;ŝŶŶĞŐĂƚŝǀĞDtͬϬ͘ϭ,njͿĨŽƌƚŚĞ
ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͘
ϭϬŝƐƚŚĞĐŽŶƐƚĂŶƚĨĂĐƚŽƌƚŚĂƚĐŽŶǀĞƌƚƐƚŚĞ&ƌĞƋƵĞŶĐLJŝĂƐ^ĞƚƚŝŶŐƵŶŝƚƐƚŽDtͬ,nj͘
>ͲϬϬϭͲϮ
:ƵůLJ͕ϮϬϭϯ



WĂŐĞϮŽĨϭϯ



^ƚĂŶĚĂƌĚ>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
&;ĐƚƵĂů&ƌĞƋƵĞŶĐLJͿŝƐƚŚĞŵĞĂƐƵƌĞĚĨƌĞƋƵĞŶĐLJŝŶ,nj͘
&^;^ĐŚĞĚƵůĞĚ&ƌĞƋƵĞŶĐLJͿŝƐϲϬ͘Ϭ,nj͕ĞdžĐĞƉƚĚƵƌŝŶŐĂƚŝŵĞĐŽƌƌĞĐƚŝŽŶ͘
/D;/ŶƚĞƌĐŚĂŶŐĞDĞƚĞƌƌƌŽƌͿŝƐƚŚĞŵĞƚĞƌĞƌƌŽƌĐŽƌƌĞĐƚŝŽŶĨĂĐƚŽƌĂŶĚƌĞƉƌĞƐĞŶƚƐƚŚĞ
ĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶƚŚĞŝŶƚĞŐƌĂƚĞĚŚŽƵƌůLJĂǀĞƌĂŐĞŽĨƚŚĞŶĞƚŝŶƚĞƌĐŚĂŶŐĞĂĐƚƵĂů;E/Ϳ
ĂŶĚƚŚĞĐƵŵƵůĂƚŝǀĞŚŽƵƌůLJŶĞƚŝŶƚĞƌĐŚĂŶŐĞĞŶĞƌŐLJŵĞĂƐƵƌĞŵĞŶƚ;ŝŶŵĞŐĂǁĂƚƚͲŚŽƵƌƐͿ͘
/d;ƵƚŽŵĂƚŝĐdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶͿŝƐƚŚĞĂĚĚŝƚŝŽŶŽĨĂĐŽŵƉŽŶĞŶƚƚŽƚŚĞ
ĞƋƵĂƚŝŽŶĨŽƌƚŚĞtĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶƚŚĂƚŵŽĚŝĨŝĞƐƚŚĞĐŽŶƚƌŽůƉŽŝŶƚĨŽƌƚŚĞ
ƉƵƌƉŽƐĞŽĨĐŽŶƚŝŶƵŽƵƐůLJƉĂLJŝŶŐďĂĐŬWƌŝŵĂƌLJ/ŶĂĚǀĞƌƚĞŶƚ/ŶƚĞƌĐŚĂŶŐĞƚŽĐŽƌƌĞĐƚ
ĂĐĐƵŵƵůĂƚĞĚƚŝŵĞĞƌƌŽƌ͘ƵƚŽŵĂƚŝĐdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶŝƐŽŶůLJĂƉƉůŝĐĂďůĞŝŶƚŚĞ
tĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͘
on/off peak

IATEC

= PII

accum

(1 − Y )* H

ǁŚĞŶŽƉĞƌĂƚŝŶŐŝŶƵƚŽŵĂƚŝĐdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶĐŽŶƚƌŽůŵŽĚĞ͘

/dƐŚĂůůďĞnjĞƌŽǁŚĞŶŽƉĞƌĂƚŝŶŐŝŶĂŶLJŽƚŚĞƌ'ŵŽĚĞ͘
•

zсͬ^͘

•

,сEƵŵďĞƌŽĨŚŽƵƌƐƵƐĞĚƚŽƉĂLJďĂĐŬWƌŝŵĂƌLJ/ŶĂĚǀĞƌƚĞŶƚ/ŶƚĞƌĐŚĂŶŐĞĞŶĞƌŐLJ͘dŚĞ
ǀĂůƵĞŽĨ,ŝƐƐĞƚƚŽϯ͘

•

^с&ƌĞƋƵĞŶĐLJŝĂƐĨŽƌƚŚĞ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ;DtͬϬ͘ϭ,njͿ͘

•

WƌŝŵĂƌLJ/ŶĂĚǀĞƌƚĞŶƚ/ŶƚĞƌĐŚĂŶŐĞ;W//ŚŽƵƌůLJͿŝƐ;ϭͲzͿΎ;//ĂĐƚƵĂůͲΎȴdͬϲͿ

•

//ĂĐƚƵĂůŝƐƚŚĞŚŽƵƌůLJ/ŶĂĚǀĞƌƚĞŶƚ/ŶƚĞƌĐŚĂŶŐĞĨŽƌƚŚĞůĂƐƚŚŽƵƌ͘

•

ȴdŝƐƚŚĞŚŽƵƌůLJĐŚĂŶŐĞŝŶƐLJƐƚĞŵdŝŵĞƌƌŽƌĂƐĚŝƐƚƌŝďƵƚĞĚďLJƚŚĞ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ
dŝŵĞDŽŶŝƚŽƌ͘tŚĞƌĞ͗



ȴdсdĞŶĚŚŽƵƌʹdďĞŐŝŶŚŽƵƌʹdĂĚũʹ;ƚͿΎ;dŽĨĨƐĞƚͿ

•

dĂĚũŝƐƚŚĞZĞůŝĂďŝůŝƚLJŽŽƌĚŝŶĂƚŽƌĂĚũƵƐƚŵĞŶƚĨŽƌĚŝĨĨĞƌĞŶĐĞƐǁŝƚŚ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ
dŝŵĞDŽŶŝƚŽƌĐŽŶƚƌŽůĐĞŶƚĞƌĐůŽĐŬƐ͘

•

ƚŝƐƚŚĞŶƵŵďĞƌŽĨŵŝŶƵƚĞƐŽĨDĂŶƵĂůdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶƚŚĂƚŽĐĐƵƌƌĞĚĚƵƌŝŶŐƚŚĞ
ŚŽƵƌ͘

•

dŽĨĨƐĞƚŝƐϬ͘ϬϬϬŽƌнϬ͘ϬϮϬŽƌͲϬ͘ϬϮϬ͘

•

W//ĂĐĐƵŵŝƐƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛ƐĂĐĐƵŵƵůĂƚĞĚW//ŚŽƵƌůLJŝŶDtŚ͘ŶKŶͲWĞĂŬĂŶĚ
KĨĨͲWĞĂŬĂĐĐƵŵƵůĂƚŝŽŶĂĐĐŽƵŶƚŝŶŐŝƐƌĞƋƵŝƌĞĚ͘
tŚĞƌĞ͗

PII

on/off peak
accum

сůĂƐƚƉĞƌŝŽĚ͛Ɛ

on/off peak

PII

accum

нW//ŚŽƵƌůLJ


ůůEZ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶƐǁŝƚŚŵƵůƚŝƉůĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐŽƉĞƌĂƚĞƵƐŝŶŐƚŚĞƉƌŝŶĐŝƉůĞƐ
ŽĨdŝĞͲůŝŶĞŝĂƐ;d>ͿŽŶƚƌŽůĂŶĚƌĞƋƵŝƌĞƚŚĞƵƐĞŽĨĂŶĞƋƵĂƚŝŽŶƐŝŵŝůĂƌƚŽƚŚĞ
>ͲϬϬϭͲϮ
:ƵůLJ͕ϮϬϭϯ



WĂŐĞϯŽĨϭϯ



^ƚĂŶĚĂƌĚ>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
ZĞƉŽƌƚŝŶŐĚĞĨŝŶĞĚĂďŽǀĞ͘ŶLJŵŽĚŝĨŝĐĂƚŝŽŶ;ƐͿƚŽƚŚŝƐƐƉĞĐŝĨŝĞĚZĞƉŽƌƚŝŶŐ
ĞƋƵĂƚŝŽŶƚŚĂƚŝƐ;ĂƌĞͿŝŵƉůĞŵĞŶƚĞĚĨŽƌĂůůƐŽŶĂŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶĂŶĚŝƐ;ĂƌĞͿĐŽŶƐŝƐƚĞŶƚ
ǁŝƚŚƚŚĞĨŽůůŽǁŝŶŐĨŽƵƌƉƌŝŶĐŝƉůĞƐǁŝůůƉƌŽǀŝĚĞĂǀĂůŝĚĂůƚĞƌŶĂƚŝǀĞZĞƉŽƌƚŝŶŐĞƋƵĂƚŝŽŶ
ĐŽŶƐŝƐƚĞŶƚǁŝƚŚƚŚĞŵĞĂƐƵƌĞƐŝŶĐůƵĚĞĚŝŶƚŚŝƐƐƚĂŶĚĂƌĚ͘
ϭ͘ ůůƉŽƌƚŝŽŶƐŽĨƚŚĞ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶĂƌĞŝŶĐůƵĚĞĚŝŶŽŶĞĂƌĞĂŽƌĂŶŽƚŚĞƌƐŽƚŚĂƚ
ƚŚĞƐƵŵŽĨĂůůĂƌĞĂŐĞŶĞƌĂƚŝŽŶ͕ůŽĂĚƐĂŶĚůŽƐƐĞƐŝƐƚŚĞƐĂŵĞĂƐƚŽƚĂůƐLJƐƚĞŵ
ŐĞŶĞƌĂƚŝŽŶ͕ůŽĂĚĂŶĚůŽƐƐĞƐ͘
Ϯ͘ dŚĞĂůŐĞďƌĂŝĐƐƵŵŽĨĂůůĂƌĞĂEĞƚ/ŶƚĞƌĐŚĂŶŐĞ^ĐŚĞĚƵůĞƐĂŶĚĂůůEĞƚ/ŶƚĞƌĐŚĂŶŐĞ
ĂĐƚƵĂůǀĂůƵĞƐŝƐĞƋƵĂůƚŽnjĞƌŽĂƚĂůůƚŝŵĞƐ͘
ϯ͘ dŚĞƵƐĞŽĨĂĐŽŵŵŽŶ^ĐŚĞĚƵůĞĚ&ƌĞƋƵĞŶĐLJ&^ĨŽƌĂůůĂƌĞĂƐĂƚĂůůƚŝŵĞƐ͘
ϰ͘ dŚĞĂďƐĞŶĐĞŽĨŵĞƚĞƌŝŶŐŽƌĐŽŵƉƵƚĂƚŝŽŶĂůĞƌƌŽƌƐ͘;dŚĞŝŶĐůƵƐŝŽŶĂŶĚƵƐĞŽĨƚŚĞ
/DƚĞƌŵƚŽĂĐĐŽƵŶƚĨŽƌŬŶŽǁŶŵĞƚĞƌŝŶŐŽƌĐŽŵƉƵƚĂƚŝŽŶĂůĞƌƌŽƌƐ͘Ϳ

/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͗tŚĞŶĐĂƉŝƚĂůŝnjĞĚ͕ĂŶLJŽŶĞŽĨƚŚĞĨŽƵƌŵĂũŽƌĞůĞĐƚƌŝĐƐLJƐƚĞŵŶĞƚǁŽƌŬƐŝŶEŽƌƚŚ
ŵĞƌŝĐĂ͗ĂƐƚĞƌŶ͕tĞƐƚĞƌŶ͕ZKdĂŶĚYƵĞďĞĐ͘ 


>ͲϬϬϭͲϮ
:ƵůLJ͕ϮϬϭϯ



WĂŐĞϰŽĨϭϯ



^ƚĂŶĚĂƌĚ>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
A. Introduction
ϭ͘

dŝƚůĞ͗

ZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ

Ϯ͘

EƵŵďĞƌ͗

>ͲϬϬϭͲϮ

ϯ͘

WƵƌƉŽƐĞ͗

dŽĐŽŶƚƌŽů/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶĨƌĞƋƵĞŶĐLJǁŝƚŚŝŶĚĞĨŝŶĞĚůŝŵŝƚƐ͘

ϰ͘

ƉƉůŝĐĂďŝůŝƚLJ͗
ϰ͘ϭ͘ ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ
ϰ͘ϭ͘ϭ ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJƌĞĐĞŝǀŝŶŐKǀĞƌůĂƉZĞŐƵůĂƚŝŽŶ^ĞƌǀŝĐĞŝƐŶŽƚƐƵďũĞĐƚ
ƚŽŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ^ƚĂŶĚĂƌĚϭ;W^ϭͿŽƌĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ
>ŝŵŝƚ;>ͿĐŽŵƉůŝĂŶĐĞĞǀĂůƵĂƚŝŽŶ͘
ϰ͘ϭ͘Ϯ ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJƚŚĂƚŝƐĂŵĞŵďĞƌŽĨĂZĞŐƵůĂƚŝŽŶZĞƐĞƌǀĞ^ŚĂƌŝŶŐ
'ƌŽƵƉŝƐƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJŽŶůLJŝŶƉĞƌŝŽĚƐĚƵƌŝŶŐǁŚŝĐŚƚŚĞ
ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJŝƐŶŽƚŝŶĂĐƚŝǀĞƐƚĂƚƵƐƵŶĚĞƌƚŚĞĂƉƉůŝĐĂďůĞ
ĂŐƌĞĞŵĞŶƚŽƌƚŚĞŐŽǀĞƌŶŝŶŐƌƵůĞƐĨŽƌƚŚĞZĞŐƵůĂƚŝŽŶZĞƐĞƌǀĞ^ŚĂƌŝŶŐ
'ƌŽƵƉ͘
ϰ͘Ϯ͘ ZĞŐƵůĂƚŝŽŶZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ

ϱ͘

;WƌŽƉŽƐĞĚͿĨĨĞĐƚŝǀĞĂƚĞ͗
ϱ͘ϭ͘



&ŝƌƐƚĚĂLJŽĨƚŚĞĨŝƌƐƚĐĂůĞŶĚĂƌƋƵĂƌƚĞƌƚŚĂƚŝƐƚǁĞůǀĞŵŽŶƚŚƐďĞLJŽŶĚƚŚĞĚĂƚĞ
ƚŚĂƚƚŚŝƐƐƚĂŶĚĂƌĚŝƐĂƉƉƌŽǀĞĚďLJĂƉƉůŝĐĂďůĞƌĞŐƵůĂƚŽƌLJĂƵƚŚŽƌŝƚŝĞƐ͕ŽƌŝŶƚŚŽƐĞ
ũƵƌŝƐĚŝĐƚŝŽŶƐǁŚĞƌĞƌĞŐƵůĂƚŽƌLJĂƉƉƌŽǀĂůŝƐŶŽƚƌĞƋƵŝƌĞĚ͕ƚŚĞƐƚĂŶĚĂƌĚďĞĐŽŵĞƐ
ĞĨĨĞĐƚŝǀĞƚŚĞĨŝƌƐƚĚĂLJŽĨƚŚĞĨŝƌƐƚĐĂůĞŶĚĂƌƋƵĂƌƚĞƌƚŚĂƚŝƐƚǁĞůǀĞŵŽŶƚŚƐ
ďĞLJŽŶĚƚŚĞĚĂƚĞƚŚŝƐƐƚĂŶĚĂƌĚŝƐĂƉƉƌŽǀĞĚďLJƚŚĞEZŽĂƌĚŽĨdƌƵƐƚĞĞƐ͕ŽƌĂƐ
ŽƚŚĞƌǁŝƐĞŵĂĚĞĞĨĨĞĐƚŝǀĞƉƵƌƐƵĂŶƚƚŽƚŚĞůĂǁƐĂƉƉůŝĐĂďůĞƚŽƐƵĐŚZK
ŐŽǀĞƌŶŵĞŶƚĂůĂƵƚŚŽƌŝƚŝĞƐ͘ 


B. ZĞƋƵŝƌĞŵĞŶƚƐ
Zϭ͘

dŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJƐŚĂůůŽƉĞƌĂƚĞƐƵĐŚƚŚĂƚƚŚĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ^ƚĂŶĚĂƌĚϭ
;W^ϭͿ͕ĐĂůĐƵůĂƚĞĚŝŶĂĐĐŽƌĚĂŶĐĞǁŝƚŚƚƚĂĐŚŵĞŶƚϭ͕ŝƐŐƌĞĂƚĞƌƚŚĂŶŽƌĞƋƵĂůƚŽϭϬϬ
ƉĞƌĐĞŶƚĨŽƌƚŚĞĂƉƉůŝĐĂďůĞ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶŝŶǁŚŝĐŚŝƚŽƉĞƌĂƚĞƐĨŽƌĞĂĐŚƉƌĞĐĞĚŝŶŐϭϮ
ĐŽŶƐĞĐƵƚŝǀĞĐĂůĞŶĚĂƌŵŽŶƚŚƉĞƌŝŽĚ͕ĞǀĂůƵĂƚĞĚŵŽŶƚŚůLJ͘΀sŝŽůĂƚŝŽŶZŝƐŬ&ĂĐƚŽƌ͗
DĞĚŝƵŵ΁΀dŝŵĞ,ŽƌŝnjŽŶ͗ZĞĂůͲƚŝŵĞKƉĞƌĂƚŝŽŶƐ΁

ZϮ͘

ĂĐŚĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJƐŚĂůůŽƉĞƌĂƚĞƐƵĐŚƚŚĂƚŝƚƐĐůŽĐŬͲŵŝŶƵƚĞĂǀĞƌĂŐĞŽĨZĞƉŽƌƚŝŶŐ
ĚŽĞƐŶŽƚĞdžĐĞĞĚŝƚƐĐůŽĐŬͲŵŝŶƵƚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ>ŝŵŝƚ;>ͿĨŽƌŵŽƌĞ
ƚŚĂŶϯϬĐŽŶƐĞĐƵƚŝǀĞĐůŽĐŬͲŵŝŶƵƚĞƐ͕ĐĂůĐƵůĂƚĞĚŝŶĂĐĐŽƌĚĂŶĐĞǁŝƚŚƚƚĂĐŚŵĞŶƚϮ͕ĨŽƌ
ƚŚĞĂƉƉůŝĐĂďůĞ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶŝŶǁŚŝĐŚƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJŽƉĞƌĂƚĞƐ͘΀sŝŽůĂƚŝŽŶ
ZŝƐŬ&ĂĐƚŽƌ͗DĞĚŝƵŵ΁΀dŝŵĞ,ŽƌŝnjŽŶ͗ZĞĂůͲƚŝŵĞKƉĞƌĂƚŝŽŶƐ΁

C. DĞĂƐƵƌĞƐ
Dϭ͘ dŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJƐŚĂůůƉƌŽǀŝĚĞĞǀŝĚĞŶĐĞ͕ƵƉŽŶƌĞƋƵĞƐƚ͕ƐƵĐŚĂƐĚĂƚĞĚĐĂůĐƵůĂƚŝŽŶ
ŽƵƚƉƵƚĨƌŽŵƐƉƌĞĂĚƐŚĞĞƚƐ͕ƐLJƐƚĞŵůŽŐƐ͕ƐŽĨƚǁĂƌĞƉƌŽŐƌĂŵƐ͕ŽƌŽƚŚĞƌĞǀŝĚĞŶĐĞ;ĞŝƚŚĞƌ
ŝŶŚĂƌĚĐŽƉLJŽƌĞůĞĐƚƌŽŶŝĐĨŽƌŵĂƚͿƚŽĚĞŵŽŶƐƚƌĂƚĞĐŽŵƉůŝĂŶĐĞǁŝƚŚZĞƋƵŝƌĞŵĞŶƚZϭ͘
>ͲϬϬϭͲϮ
:ƵůLJ͕ϮϬϭϯ



WĂŐĞϱŽĨϭϯ



^ƚĂŶĚĂƌĚ>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
DϮ͘ ĂĐŚĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJƐŚĂůůƉƌŽǀŝĚĞĞǀŝĚĞŶĐĞ͕ƵƉŽŶƌĞƋƵĞƐƚ͕ƐƵĐŚĂƐĚĂƚĞĚ
ĐĂůĐƵůĂƚŝŽŶŽƵƚƉƵƚĨƌŽŵƐƉƌĞĂĚƐŚĞĞƚƐ͕ƐLJƐƚĞŵůŽŐƐ͕ƐŽĨƚǁĂƌĞƉƌŽŐƌĂŵƐ͕ŽƌŽƚŚĞƌ
ĞǀŝĚĞŶĐĞ;ĞŝƚŚĞƌŝŶŚĂƌĚĐŽƉLJŽƌĞůĞĐƚƌŽŶŝĐĨŽƌŵĂƚͿƚŽĚĞŵŽŶƐƚƌĂƚĞĐŽŵƉůŝĂŶĐĞǁŝƚŚ
ZĞƋƵŝƌĞŵĞŶƚZϮ͘
D. ŽŵƉůŝĂŶĐĞ
ϭ͘

ŽŵƉůŝĂŶĐĞDŽŶŝƚŽƌŝŶŐWƌŽĐĞƐƐ
ϭ͘ϭ͘ ŽŵƉůŝĂŶĐĞŶĨŽƌĐĞŵĞŶƚƵƚŚŽƌŝƚLJ
ƐĚĞĨŝŶĞĚŝŶƚŚĞEZZƵůĞƐŽĨWƌŽĐĞĚƵƌĞ͕͞ŽŵƉůŝĂŶĐĞŶĨŽƌĐĞŵĞŶƚƵƚŚŽƌŝƚLJ͟
ŵĞĂŶƐEZŽƌƚŚĞZĞŐŝŽŶĂůŶƚŝƚLJŝŶƚŚĞŝƌƌĞƐƉĞĐƚŝǀĞƌŽůĞƐŽĨŵŽŶŝƚŽƌŝŶŐĂŶĚ
ĞŶĨŽƌĐŝŶŐĐŽŵƉůŝĂŶĐĞǁŝƚŚƚŚĞEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚƐ͘
ϭ͘Ϯ͘ ĂƚĂZĞƚĞŶƚŝŽŶ
dŚĞĨŽůůŽǁŝŶŐĞǀŝĚĞŶĐĞƌĞƚĞŶƚŝŽŶƉĞƌŝŽĚƐŝĚĞŶƚŝĨLJƚŚĞƉĞƌŝŽĚŽĨƚŝŵĞĂŶĞŶƚŝƚLJŝƐ
ƌĞƋƵŝƌĞĚƚŽƌĞƚĂŝŶƐƉĞĐŝĨŝĐĞǀŝĚĞŶĐĞƚŽĚĞŵŽŶƐƚƌĂƚĞĐŽŵƉůŝĂŶĐĞ͘&ŽƌŝŶƐƚĂŶĐĞƐ
ǁŚĞƌĞƚŚĞĞǀŝĚĞŶĐĞƌĞƚĞŶƚŝŽŶƉĞƌŝŽĚƐƉĞĐŝĨŝĞĚďĞůŽǁŝƐƐŚŽƌƚĞƌƚŚĂŶƚŚĞƚŝŵĞ
ƐŝŶĐĞƚŚĞůĂƐƚĂƵĚŝƚ͕ƚŚĞŽŵƉůŝĂŶĐĞŶĨŽƌĐĞŵĞŶƚƵƚŚŽƌŝƚLJŵĂLJĂƐŬĂŶĞŶƚŝƚLJƚŽ
ƉƌŽǀŝĚĞŽƚŚĞƌĞǀŝĚĞŶĐĞƚŽƐŚŽǁƚŚĂƚŝƚǁĂƐĐŽŵƉůŝĂŶƚĨŽƌƚŚĞĨƵůůͲƚŝŵĞƉĞƌŝŽĚ
ƐŝŶĐĞƚŚĞůĂƐƚĂƵĚŝƚ͘
dŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJƐŚĂůůƌĞƚĂŝŶĚĂƚĂŽƌĞǀŝĚĞŶĐĞƚŽƐŚŽǁĐŽŵƉůŝĂŶĐĞĨŽƌƚŚĞ
ĐƵƌƌĞŶƚLJĞĂƌ͕ƉůƵƐƚŚƌĞĞƉƌĞǀŝŽƵƐĐĂůĞŶĚĂƌLJĞĂƌƐƵŶůĞƐƐ͕ĚŝƌĞĐƚĞĚďLJŝƚƐ
ŽŵƉůŝĂŶĐĞŶĨŽƌĐĞŵĞŶƚƵƚŚŽƌŝƚLJ͕ƚŽƌĞƚĂŝŶƐƉĞĐŝĨŝĐĞǀŝĚĞŶĐĞĨŽƌĂůŽŶŐĞƌ
ƉĞƌŝŽĚŽĨƚŝŵĞĂƐƉĂƌƚŽĨĂŶŝŶǀĞƐƚŝŐĂƚŝŽŶ͘ĂƚĂƌĞƋƵŝƌĞĚĨŽƌƚŚĞĐĂůĐƵůĂƚŝŽŶŽĨ
ZĞŐƵůĂƚŝŽŶZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉZĞƉŽƌƚŝŶŐĐĞ͕ŽƌZĞƉŽƌƚŝŶŐ͕W^ϭ͕ĂŶĚ
>ƐŚĂůůďĞƌĞƚĂŝŶĞĚŝŶĚŝŐŝƚĂůĨŽƌŵĂƚĂƚƚŚĞƐĂŵĞƐĐĂŶƌĂƚĞĂƚǁŚŝĐŚƚŚĞ
ZĞƉŽƌƚŝŶŐŝƐĐĂůĐƵůĂƚĞĚĨŽƌƚŚĞĐƵƌƌĞŶƚLJĞĂƌ͕ƉůƵƐƚŚƌĞĞƉƌĞǀŝŽƵƐĐĂůĞŶĚĂƌ
LJĞĂƌƐ͘
/ĨĂZĞƐƉŽŶƐŝďůĞŶƚŝƚLJŝƐĨŽƵŶĚŶŽŶĐŽŵƉůŝĂŶƚ͕ŝƚƐŚĂůůŬĞĞƉŝŶĨŽƌŵĂƚŝŽŶƌĞůĂƚĞĚƚŽ
ƚŚĞŶŽŶĐŽŵƉůŝĂŶĐĞƵŶƚŝůĨŽƵŶĚĐŽŵƉůŝĂŶƚ͕ŽƌĨŽƌƚŚĞƚŝŵĞƉĞƌŝŽĚƐƉĞĐŝĨŝĞĚĂďŽǀĞ͕
ǁŚŝĐŚĞǀĞƌŝƐůŽŶŐĞƌ͘
dŚĞŽŵƉůŝĂŶĐĞŶĨŽƌĐĞŵĞŶƚƵƚŚŽƌŝƚLJƐŚĂůůŬĞĞƉƚŚĞůĂƐƚĂƵĚŝƚƌĞĐŽƌĚƐĂŶĚĂůů
ƐƵďƐĞƋƵĞŶƚƌĞƋƵĞƐƚĞĚĂŶĚƐƵďŵŝƚƚĞĚƌĞĐŽƌĚƐ͘
ϭ͘ϯ͘ ŽŵƉůŝĂŶĐĞDŽŶŝƚŽƌŝŶŐĂŶĚƐƐĞƐƐŵĞŶƚWƌŽĐĞƐƐĞƐ
ŽŵƉůŝĂŶĐĞƵĚŝƚƐ
^ĞůĨͲĞƌƚŝĨŝĐĂƚŝŽŶƐ
^ƉŽƚŚĞĐŬŝŶŐ
ŽŵƉůŝĂŶĐĞ/ŶǀĞƐƚŝŐĂƚŝŽŶ
^ĞůĨͲZĞƉŽƌƚŝŶŐ
ŽŵƉůĂŝŶƚƐ

>ͲϬϬϭͲϮ
:ƵůLJ͕ϮϬϭϯ



WĂŐĞϲŽĨϭϯ



^ƚĂŶĚĂƌĚ>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
ϭ͘ϰ͘ ĚĚŝƚŝŽŶĂůŽŵƉůŝĂŶĐĞ/ŶĨŽƌŵĂƚŝŽŶ
EŽŶĞ͘
Ϯ͘

sŝŽůĂƚŝŽŶ^ĞǀĞƌŝƚLJ>ĞǀĞůƐ
R
#

Lower VSL

Zϭ dŚĞW^ϭǀĂůƵĞ
ŽĨƚŚĞ
ZĞƐƉŽŶƐŝďůĞ
ŶƚŝƚLJ͕ĨŽƌƚŚĞ
ƉƌĞĐĞĚŝŶŐϭϮ
ĐŽŶƐĞĐƵƚŝǀĞ
ĐĂůĞŶĚĂƌŵŽŶƚŚ
ƉĞƌŝŽĚ͕ŝƐůĞƐƐ
ƚŚĂŶϭϬϬ
ƉĞƌĐĞŶƚďƵƚ
ŐƌĞĂƚĞƌƚŚĂŶŽƌ
ĞƋƵĂůƚŽϵϱ
ƉĞƌĐĞŶƚĨŽƌƚŚĞ
ĂƉƉůŝĐĂďůĞ
/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͘
ZϮ dŚĞĂůĂŶĐŝŶŐ
ƵƚŚŽƌŝƚLJ
ĞdžĐĞĞĚĞĚŝƚƐ
ĐůŽĐŬͲŵŝŶƵƚĞ
>ĨŽƌŵŽƌĞ
ƚŚĂŶϯϬ
ĐŽŶƐĞĐƵƚŝǀĞ
ĐůŽĐŬŵŝŶƵƚĞƐ
ďƵƚĨŽƌϰϱ
ĐŽŶƐĞĐƵƚŝǀĞ
ĐůŽĐŬͲŵŝŶƵƚĞƐ
ŽƌůĞƐƐĨŽƌƚŚĞ
ĂƉƉůŝĐĂďůĞ
/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͘

Moderate VSL

High VSL

Severe VSL

dŚĞW^ϭǀĂůƵĞ
ŽĨƚŚĞ
ZĞƐƉŽŶƐŝďůĞ
ŶƚŝƚLJ͕ĨŽƌƚŚĞ
ƉƌĞĐĞĚŝŶŐϭϮ
ĐŽŶƐĞĐƵƚŝǀĞ
ĐĂůĞŶĚĂƌŵŽŶƚŚ
ƉĞƌŝŽĚ͕ŝƐůĞƐƐ
ƚŚĂŶϵϱƉĞƌĐĞŶƚ͕
ďƵƚŐƌĞĂƚĞƌƚŚĂŶ
ŽƌĞƋƵĂůƚŽϵϬ
ƉĞƌĐĞŶƚĨŽƌƚŚĞ
ĂƉƉůŝĐĂďůĞ
/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͘

dŚĞW^ϭǀĂůƵĞ
ŽĨƚŚĞ
ZĞƐƉŽŶƐŝďůĞ
ŶƚŝƚLJ͕ĨŽƌƚŚĞ
ƉƌĞĐĞĚŝŶŐϭϮ
ĐŽŶƐĞĐƵƚŝǀĞ
ĐĂůĞŶĚĂƌŵŽŶƚŚ
ƉĞƌŝŽĚ͕ŝƐůĞƐƐ
ƚŚĂŶϵϬƉĞƌĐĞŶƚ͕
ďƵƚŐƌĞĂƚĞƌƚŚĂŶ
ŽƌĞƋƵĂůƚŽϴϱ
ƉĞƌĐĞŶƚĨŽƌƚŚĞ
ĂƉƉůŝĐĂďůĞ
/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͘

dŚĞW^ϭǀĂůƵĞŽĨƚŚĞ
ZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͕ĨŽƌ
ƚŚĞƉƌĞĐĞĚŝŶŐϭϮ
ĐŽŶƐĞĐƵƚŝǀĞĐĂůĞŶĚĂƌ
ŵŽŶƚŚƉĞƌŝŽĚ͕ŝƐůĞƐƐ
ƚŚĂŶϴϱƉĞƌĐĞŶƚĨŽƌƚŚĞ
ĂƉƉůŝĐĂďůĞ
/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͘

dŚĞĂůĂŶĐŝŶŐ
ƵƚŚŽƌŝƚLJ
ĞdžĐĞĞĚĞĚŝƚƐ
ĐůŽĐŬͲŵŝŶƵƚĞ
>ĨŽƌŐƌĞĂƚĞƌ
ƚŚĂŶϰϱ
ĐŽŶƐĞĐƵƚŝǀĞ
ĐůŽĐŬŵŝŶƵƚĞƐ
ďƵƚĨŽƌϲϬ
ĐŽŶƐĞĐƵƚŝǀĞ
ĐůŽĐŬͲŵŝŶƵƚĞƐ
ŽƌůĞƐƐĨŽƌƚŚĞ
ĂƉƉůŝĐĂďůĞ
/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͘

dŚĞĂůĂŶĐŝŶŐ
ƵƚŚŽƌŝƚLJ
ĞdžĐĞĞĚĞĚŝƚƐ
ĐůŽĐŬͲŵŝŶƵƚĞ
>ĨŽƌŐƌĞĂƚĞƌ
ƚŚĂŶϲϬ
ĐŽŶƐĞĐƵƚŝǀĞ
ĐůŽĐŬŵŝŶƵƚĞƐ
ďƵƚĨŽƌϳϱ
ĐŽŶƐĞĐƵƚŝǀĞ
ĐůŽĐŬͲŵŝŶƵƚĞƐ
ŽƌůĞƐƐĨŽƌƚŚĞ
ĂƉƉůŝĐĂďůĞ
/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͘

dŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ
ĞdžĐĞĞĚĞĚŝƚƐĐůŽĐŬͲ
ŵŝŶƵƚĞ>ĨŽƌŐƌĞĂƚĞƌ
ƚŚĂŶϳϱĐŽŶƐĞĐƵƚŝǀĞ
ĐůŽĐŬͲŵŝŶƵƚĞƐĨŽƌƚŚĞ
ĂƉƉůŝĐĂďůĞ
/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͘

E. ZĞŐŝŽŶĂůsĂƌŝĂŶĐĞƐ
EŽŶĞ͘
F. ƐƐŽĐŝĂƚĞĚŽĐƵŵĞŶƚƐ
>ͲϬϬϭͲϮ͕ZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ^ƚĂŶĚĂƌĚĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ

>ͲϬϬϭͲϮ
:ƵůLJ͕ϮϬϭϯ



WĂŐĞϳŽĨϭϯ



^ƚĂŶĚĂƌĚ>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
sĞƌƐŝŽŶ,ŝƐƚŽƌLJ
sĞƌƐŝŽŶ

ĂƚĞ

ĐƚŝŽŶ

ŚĂŶŐĞdƌĂĐŬŝŶŐ

Ϭ

&ĞďƌƵĂƌLJϴ͕
ϮϬϬϱ

KdƉƉƌŽǀĂů

EĞǁ

Ϭ

Ɖƌŝůϭ͕ϮϬϬϱ

ĨĨĞĐƚŝǀĞ/ŵƉůĞŵĞŶƚĂƚŝŽŶĂƚĞ

EĞǁ

Ϭ

ƵŐƵƐƚϴ͕ϮϬϬϱ

ZĞŵŽǀĞĚ͞WƌŽƉŽƐĞĚ͟ĨƌŽŵĨĨĞĐƚŝǀĞĂƚĞ

ƌƌĂƚĂ

Ϭ

:ƵůLJϮϰ͕ϮϬϬϳ

ŽƌƌĞĐƚĞĚZϯƚŽƌĞĨĞƌĞŶĐĞDϭĂŶĚDϮ
ŝŶƐƚĞĂĚŽĨZϭĂŶĚZϮ

ƌƌĂƚĂ

ϬĂ

ĞĐĞŵďĞƌϭϵ͕
ϮϬϬϳ

ĚĚĞĚƉƉĞŶĚŝdžϮʹ/ŶƚĞƌƉƌĞƚĂƚŝŽŶŽĨZϭ
ĂƉƉƌŽǀĞĚďLJKdŽŶKĐƚŽďĞƌϮϯ͕ϮϬϬϳ

ZĞǀŝƐĞĚ

ϬĂ

:ĂŶƵĂƌLJϭϲ͕
ϮϬϬϴ

/Ŷ^ĞĐƚŝŽŶ͘Ϯ͕͘ĚĚĞĚ͞Ă͟ƚŽĞŶĚŽĨ
ƐƚĂŶĚĂƌĚŶƵŵďĞƌ
/Ŷ^ĞĐƚŝŽŶ&͕ĐŽƌƌĞĐƚĞĚĂƵƚŽŵĂƚŝĐ
ŶƵŵďĞƌŝŶŐĨƌŽŵ͞Ϯ͟ƚŽ͞ϭ͟ĂŶĚƌĞŵŽǀĞĚ
͞ĂƉƉƌŽǀĞĚ͟ĂŶĚĂĚĚĞĚƉĂƌĞŶƚŚĞƐŝƐƚŽ
͞;KĐƚŽďĞƌϮϯ͕ϮϬϬϳͿ͟

ƌƌĂƚĂ

Ϭ

:ĂŶƵĂƌLJϮϯ͕
ϮϬϬϴ

ZĞǀĞƌƐĞĚĞƌƌĂƚĂĐŚĂŶŐĞĨƌŽŵ:ƵůLJϮϰ͕ϮϬϬϳ

ƌƌĂƚĂ

Ϭ͘ϭĂ

KĐƚŽďĞƌϮϵ͕
ϮϬϬϴ

ŽĂƌĚĂƉƉƌŽǀĞĚĞƌƌĂƚĂĐŚĂŶŐĞƐ͖ƵƉĚĂƚĞĚ
ǀĞƌƐŝŽŶŶƵŵďĞƌƚŽ͞Ϭ͘ϭĂ͟

ƌƌĂƚĂ

Ϭ͘ϭĂ

DĂLJϭϯ͕ϮϬϬϵ

ƉƉƌŽǀĞĚďLJ&Z





/ŶĐůƵƐŝŽŶŽĨ>ĂŶĚtsĂƌŝĂŶĐĞĂŶĚ
ĞdžĐůƵƐŝŽŶŽĨW^Ϯ

ZĞǀŝƐŝŽŶ

ϭ

>ͲϬϬϭͲϮ
:ƵůLJ͕ϮϬϭϯ



WĂŐĞϴŽĨϭϯ



^ƚĂŶĚĂƌĚ>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
ƚƚĂĐŚŵĞŶƚϭ
ƋƵĂƚŝŽŶƐ^ƵƉƉŽƌƚŝŶŐZĞƋƵŝƌĞŵĞŶƚZϭĂŶĚDĞĂƐƵƌĞDϭ

W^ϭŝƐĐĂůĐƵůĂƚĞĚĂƐĨŽůůŽǁƐ͗

W^ϭс;ϮͲ&ͿΎϭϬϬй

dŚĞĨƌĞƋƵĞŶĐLJͲƌĞůĂƚĞĚĐŽŵƉůŝĂŶĐĞĨĂĐƚŽƌ;&Ϳ͕ŝƐĂƌĂƚŝŽŽĨƚŚĞĂĐĐƵŵƵůĂƚŝŶŐĐůŽĐŬͲŵŝŶƵƚĞ
ĐŽŵƉůŝĂŶĐĞƉĂƌĂŵĞƚĞƌƐĨŽƌƚŚĞŵŽƐƚƌĞĐĞŶƚƉƌĞĐĞĚŝŶŐϭϮĐŽŶƐĞĐƵƚŝǀĞĐĂůĞŶĚĂƌŵŽŶƚŚƐ͕
ĚŝǀŝĚĞĚďLJƚŚĞƐƋƵĂƌĞŽĨƚŚĞƚĂƌŐĞƚĨƌĞƋƵĞŶĐLJďŽƵŶĚ͗
& с

& ϭϮͲ ŵŽŶƚŚ
;ɸϭ/ͿϮ

tŚĞƌĞɸϭ/ŝƐƚŚĞĐŽŶƐƚĂŶƚĚĞƌŝǀĞĚĨƌŽŵĂƚĂƌŐĞƚĞĚĨƌĞƋƵĞŶĐLJďŽƵŶĚĨŽƌĞĂĐŚ
/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶĂƐĨŽůůŽǁƐ͗
•

ĂƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶɸϭ/сϬ͘Ϭϭϴ,nj

•

tĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶɸϭ/сϬ͘ϬϮϮϴ,nj

•

ZKd/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶɸϭ/сϬ͘ϬϯϬ,nj

•

YƵĞďĞĐ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶɸϭ/сϬ͘ϬϮϭ,nj

dŚĞƌĂƚŝŶŐŝŶĚĞdž&ϭϮͲŵŽŶƚŚŝƐĚĞƌŝǀĞĚĨƌŽŵƚŚĞŵŽƐƚƌĞĐĞŶƚƉƌĞĐĞĚŝŶŐϭϮĐŽŶƐĞĐƵƚŝǀĞ
ĐĂůĞŶĚĂƌŵŽŶƚŚƐŽĨĚĂƚĂ͘dŚĞĂĐĐƵŵƵůĂƚŝŶŐĐůŽĐŬͲŵŝŶƵƚĞĐŽŵƉůŝĂŶĐĞƉĂƌĂŵĞƚĞƌƐĂƌĞ
ĚĞƌŝǀĞĚĨƌŽŵƚŚĞŽŶĞͲŵŝŶƵƚĞĂǀĞƌĂŐĞƐŽĨZĞƉŽƌƚŝŶŐ͕&ƌĞƋƵĞŶĐLJƌƌŽƌ͕ĂŶĚ&ƌĞƋƵĞŶĐLJ
ŝĂƐ^ĞƚƚŝŶŐƐ͘
ĐůŽĐŬͲŵŝŶƵƚĞĂǀĞƌĂŐĞŝƐƚŚĞĂǀĞƌĂŐĞŽĨƚŚĞƌĞƉŽƌƚŝŶŐĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛ƐǀĂůŝĚ
ŵĞĂƐƵƌĞĚǀĂƌŝĂďůĞ;ŝ͘Ğ͕͘ĨŽƌZĞƉŽƌƚŝŶŐ;ZͿĂŶĚĨŽƌ&ƌĞƋƵĞŶĐLJƌƌŽƌͿĨŽƌĞĂĐŚ
ƐĂŵƉůŝŶŐĐLJĐůĞĚƵƌŝŶŐĂŐŝǀĞŶĐůŽĐŬͲŵŝŶƵƚĞ͘

§ RACE·
¨
¸
© − 10 B ¹clock -minute

§ ¦ RACE
sampling cycles in clock - minute
¨
¨
nsampling cycles in clock -minute
=©
- 10B

·
¸
¸
¹

ŶĚ͕

¦ ΔF

ΔFclock -minute =

sampling cycles in clock - minute

nsampling cycles in clock -minute

dŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛ƐĐůŽĐŬͲŵŝŶƵƚĞĐŽŵƉůŝĂŶĐĞĨĂĐƚŽƌ;&ĐůŽĐŬͲŵŝŶƵƚĞͿĐĂůĐƵůĂƚŝŽŶŝƐ͗

>ͲϬϬϭͲϮ
:ƵůLJ͕ϮϬϭϯ



WĂŐĞϵŽĨϭϯ



^ƚĂŶĚĂƌĚ>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
ª§ RACE·
º
* ΔFclock -minute »
CFclock -minute = Ǭ
¸
¬© − 10 B ¹ clock -minute
¼
EŽƌŵĂůůLJ͕ϲϬĐůŽĐŬͲŵŝŶƵƚĞĂǀĞƌĂŐĞƐŽĨƚŚĞƌĞƉŽƌƚŝŶŐĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛ƐZĞƉŽƌƚŝŶŐ
ĂŶĚ&ƌĞƋƵĞŶĐLJƌƌŽƌǁŝůůďĞƵƐĞĚƚŽĐŽŵƉƵƚĞƚŚĞŚŽƵƌůLJĂǀĞƌĂŐĞĐŽŵƉůŝĂŶĐĞĨĂĐƚŽƌ;&ĐůŽĐŬͲ
ŚŽƵƌͿ͘

CFclock -hour =

¦ CF

clock - minute

nclock -minute samples in hour

dŚĞƌĞƉŽƌƚŝŶŐĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJƐŚĂůůďĞĂďůĞƚŽƌĞĐĂůĐƵůĂƚĞĂŶĚƐƚŽƌĞĞĂĐŚŽĨƚŚĞ
ƌĞƐƉĞĐƚŝǀĞĐůŽĐŬͲŚŽƵƌĂǀĞƌĂŐĞƐ;&ĐůŽĐŬͲŚŽƵƌĂǀĞƌĂŐĞͲŵŽŶƚŚͿĂŶĚƚŚĞĚĂƚĂƐĂŵƉůĞƐĨŽƌĞĂĐŚϮϰͲ
ŚŽƵƌƉĞƌŝŽĚ;ŽŶĞĨŽƌĞĂĐŚĐůŽĐŬͲŚŽƵƌ͖ŝ͘Ğ͕͘ŚŽƵƌĞŶĚŝŶŐ;,ͿϬϭϬϬ͕,ϬϮϬϬ͕͕͘͘͘,ϮϰϬϬͿ͘
dŽĐĂůĐƵůĂƚĞƚŚĞŵŽŶƚŚůLJĐŽŵƉůŝĂŶĐĞĨĂĐƚŽƌ;&ŵŽŶƚŚͿ͗

¦ [(CF
¦ [n

clock - hour

CFclock -hour average - month =

)( none -minute samples in clock - hour )]

days -in - month

one - minute samples in clock - hour
days - in month

¦ [(CF

clock - hour average - month

CFmonth =

hours - in - day

¦ [n

]

)( none - minute samples in clock - hour averages )]

one - minute samples in clock - hour averages

]

hours - in day

dŽĐĂůĐƵůĂƚĞƚŚĞϭϮͲŵŽŶƚŚĐŽŵƉůŝĂŶĐĞĨĂĐƚŽƌ;&ϭϮŵŽŶƚŚͿ͗
12

¦ (CF

month -i

CF12-month =

i =1

)(n(one -minute samples in month )−i )]

12

¦ [n

( one -minute samples in month) -i

]

i =1

dŽĞŶƐƵƌĞƚŚĂƚƚŚĞĂǀĞƌĂŐĞZĞƉŽƌƚŝŶŐĂŶĚ&ƌĞƋƵĞŶĐLJƌƌŽƌĐĂůĐƵůĂƚĞĚĨŽƌĂŶLJŽŶĞͲ
ŵŝŶƵƚĞŝŶƚĞƌǀĂůŝƐƌĞƉƌĞƐĞŶƚĂƚŝǀĞŽĨƚŚĂƚƚŝŵĞŝŶƚĞƌǀĂů͕ŝƚŝƐŶĞĐĞƐƐĂƌLJƚŚĂƚĂƚůĞĂƐƚϱϬ
ƉĞƌĐĞŶƚŽĨďŽƚŚƚŚĞZĞƉŽƌƚŝŶŐĂŶĚ&ƌĞƋƵĞŶĐLJƌƌŽƌƐĂŵƉůĞĚĂƚĂĚƵƌŝŶŐƚŚĞŽŶĞͲ
ŵŝŶƵƚĞŝŶƚĞƌǀĂůŝƐǀĂůŝĚ͘/ĨƚŚĞƌĞĐŽƌĚŝŶŐŽĨZĞƉŽƌƚŝŶŐŽƌ&ƌĞƋƵĞŶĐLJƌƌŽƌŝƐŝŶƚĞƌƌƵƉƚĞĚ
ƐƵĐŚƚŚĂƚůĞƐƐƚŚĂŶϱϬƉĞƌĐĞŶƚŽĨƚŚĞŽŶĞͲŵŝŶƵƚĞƐĂŵƉůĞƉĞƌŝŽĚĚĂƚĂŝƐĂǀĂŝůĂďůĞŽƌǀĂůŝĚ͕
ƚŚĞŶƚŚĂƚŽŶĞͲŵŝŶƵƚĞŝŶƚĞƌǀĂůŝƐĞdžĐůƵĚĞĚĨƌŽŵƚŚĞW^ϭĐĂůĐƵůĂƚŝŽŶ͘

ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJƉƌŽǀŝĚŝŶŐKǀĞƌůĂƉZĞŐƵůĂƚŝŽŶ^ĞƌǀŝĐĞƚŽĂŶŽƚŚĞƌĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ
ĐĂůĐƵůĂƚĞƐŝƚƐW^ϭƉĞƌĨŽƌŵĂŶĐĞĂĨƚĞƌĐŽŵďŝŶŝŶŐŝƚƐZĞƉŽƌƚŝŶŐĂŶĚ&ƌĞƋƵĞŶĐLJŝĂƐ
>ͲϬϬϭͲϮ
:ƵůLJ͕ϮϬϭϯ



WĂŐĞϭϬŽĨϭϯ



^ƚĂŶĚĂƌĚ>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
^ĞƚƚŝŶŐƐǁŝƚŚƚŚĞZĞƉŽƌƚŝŶŐĂŶĚ&ƌĞƋƵĞŶĐLJŝĂƐ^ĞƚƚŝŶŐƐŽĨƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ
ƌĞĐĞŝǀŝŶŐƚŚĞZĞŐƵůĂƚŝŽŶ^ĞƌǀŝĐĞ͘



>ͲϬϬϭͲϮ
:ƵůLJ͕ϮϬϭϯ



WĂŐĞϭϭŽĨϭϯ



^ƚĂŶĚĂƌĚ>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
ƚƚĂĐŚŵĞŶƚϮ

ƋƵĂƚŝŽŶƐ^ƵƉƉŽƌƚŝŶŐZĞƋƵŝƌĞŵĞŶƚZϮĂŶĚDĞĂƐƵƌĞDϮ


tŚĞŶĂĐƚƵĂůĨƌĞƋƵĞŶĐLJŝƐĞƋƵĂůƚŽ^ĐŚĞĚƵůĞĚ&ƌĞƋƵĞŶĐLJ͕>,ŝŐŚĂŶĚ>>ŽǁĚŽŶŽƚĂƉƉůLJ͘
tŚĞŶĂĐƚƵĂůĨƌĞƋƵĞŶĐLJŝƐůĞƐƐƚŚĂŶ^ĐŚĞĚƵůĞĚ&ƌĞƋƵĞŶĐLJ͕>,ŝŐŚĚŽĞƐŶŽƚĂƉƉůLJ͕ĂŶĚ
>>ŽǁŝƐĐĂůĐƵůĂƚĞĚĂƐ͗
BAAL Low = (− 10 Bi × (FTL Low − FS ))×

(FTL Low − FS )
(FA − FS )

tŚĞŶĂĐƚƵĂůĨƌĞƋƵĞŶĐLJŝƐŐƌĞĂƚĞƌƚŚĂŶ^ĐŚĞĚƵůĞĚ&ƌĞƋƵĞŶĐLJ͕>>ŽǁĚŽĞƐŶŽƚĂƉƉůLJĂŶĚ
ƚŚĞ>,ŝŐŚŝƐĐĂůĐƵůĂƚĞĚĂƐ͗
BAALHigh = (− 10 Bi × (FTLHigh − FS ))×

(FTL

High

− FS )

(FA − FS )

tŚĞƌĞ͗
>>ŽǁŝƐƚŚĞ>ŽǁĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ>ŝŵŝƚ;DtͿ
>,ŝŐŚŝƐƚŚĞ,ŝŐŚĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ>ŝŵŝƚ;DtͿ
ϭϬŝƐĂĐŽŶƐƚĂŶƚƚŽĐŽŶǀĞƌƚƚŚĞ&ƌĞƋƵĞŶĐLJŝĂƐ^ĞƚƚŝŶŐĨƌŽŵDtͬϬ͘ϭ,njƚŽDtͬ,nj
ŝŝƐƚŚĞ&ƌĞƋƵĞŶĐLJŝĂƐ^ĞƚƚŝŶŐĨŽƌĂĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ;ĞdžƉƌĞƐƐĞĚĂƐDtͬϬ͘ϭ,njͿ
&ŝƐƚŚĞŵĞĂƐƵƌĞĚĨƌĞƋƵĞŶĐLJŝŶ,nj͘
&^ŝƐƚŚĞƐĐŚĞĚƵůĞĚĨƌĞƋƵĞŶĐLJŝŶ,nj͘
&d>>ŽǁŝƐƚŚĞ>Žǁ&ƌĞƋƵĞŶĐLJdƌŝŐŐĞƌ>ŝŵŝƚ;ĐĂůĐƵůĂƚĞĚĂƐ&^Ͳϯɸϭ/,njͿ
&d>,ŝŐŚŝƐƚŚĞ,ŝŐŚ&ƌĞƋƵĞŶĐLJdƌŝŐŐĞƌ>ŝŵŝƚ;ĐĂůĐƵůĂƚĞĚĂƐ&^нϯɸϭ/,njͿ
tŚĞƌĞɸϭ/ŝƐƚŚĞĐŽŶƐƚĂŶƚĚĞƌŝǀĞĚĨƌŽŵĂƚĂƌŐĞƚĞĚĨƌĞƋƵĞŶĐLJďŽƵŶĚĨŽƌĞĂĐŚ
/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶĂƐĨŽůůŽǁƐ͗
•

ĂƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶɸϭ/сϬ͘Ϭϭϴ,nj

•

tĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶɸϭ/сϬ͘ϬϮϮϴ,nj

•

ZKd/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶɸϭ/сϬ͘ϬϯϬ,nj

•

YƵĞďĞĐ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶɸϭ/сϬ͘ϬϮϭ,nj


dŽĞŶƐƵƌĞƚŚĂƚƚŚĞĂǀĞƌĂŐĞĂĐƚƵĂůĨƌĞƋƵĞŶĐLJĐĂůĐƵůĂƚĞĚĨŽƌĂŶLJŽŶĞͲŵŝŶƵƚĞŝŶƚĞƌǀĂůŝƐ
ƌĞƉƌĞƐĞŶƚĂƚŝǀĞŽĨƚŚĂƚƚŝŵĞŝŶƚĞƌǀĂů͕ŝƚŝƐŶĞĐĞƐƐĂƌLJƚŚĂƚĂƚůĞĂƐƚϱϬйŽĨƚŚĞĂĐƚƵĂů
ĨƌĞƋƵĞŶĐLJƐĂŵƉůĞĚĂƚĂĚƵƌŝŶŐƚŚĂƚŽŶĞͲŵŝŶƵƚĞŝŶƚĞƌǀĂůŝƐǀĂůŝĚ͘/ĨƚŚĞƌĞĐŽƌĚŝŶŐŽĨĂĐƚƵĂů
ĨƌĞƋƵĞŶĐLJŝƐŝŶƚĞƌƌƵƉƚĞĚƐƵĐŚƚŚĂƚůĞƐƐƚŚĂŶϱϬƉĞƌĐĞŶƚŽĨƚŚĞŽŶĞͲŵŝŶƵƚĞƐĂŵƉůĞƉĞƌŝŽĚ
>ͲϬϬϭͲϮ
:ƵůLJ͕ϮϬϭϯ



WĂŐĞϭϮŽĨϭϯ



^ƚĂŶĚĂƌĚ>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
ĚĂƚĂŝƐĂǀĂŝůĂďůĞŽƌǀĂůŝĚ͕ƚŚĞŶƚŚĂƚŽŶĞͲŵŝŶƵƚĞŝŶƚĞƌǀĂůŝƐĞdžĐůƵĚĞĚĨƌŽŵƚŚĞ>
ĐĂůĐƵůĂƚŝŽŶĂŶĚƚŚĞϯϬͲŵŝŶƵƚĞĐůŽĐŬǁŽƵůĚďĞƌĞƐĞƚƚŽnjĞƌŽ͘

ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJƉƌŽǀŝĚŝŶŐKǀĞƌůĂƉZĞŐƵůĂƚŝŽŶ^ĞƌǀŝĐĞƚŽĂŶŽƚŚĞƌĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ
ĐĂůĐƵůĂƚĞƐŝƚƐ>ƉĞƌĨŽƌŵĂŶĐĞĂĨƚĞƌĐŽŵďŝŶŝŶŐŝƚƐ&ƌĞƋƵĞŶĐLJŝĂƐ^ĞƚƚŝŶŐǁŝƚŚƚŚĞ
&ƌĞƋƵĞŶĐLJŝĂƐ^ĞƚƚŝŶŐŽĨƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJƌĞĐĞŝǀŝŶŐKǀĞƌůĂƉZĞŐƵůĂƚŝŽŶ^ĞƌǀŝĐĞ͘


>ͲϬϬϭͲϮ
:ƵůLJ͕ϮϬϭϯ



WĂŐĞϭϯŽĨϭϯ



^ƚĂŶĚĂƌĚ>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ

^ƚĂŶĚĂƌĚĞǀĞůŽƉŵĞŶƚZŽĂĚŵĂƉ
dŚŝƐƐĞĐƚŝŽŶŝƐŵĂŝŶƚĂŝŶĞĚďLJƚŚĞĚƌĂĨƚŝŶŐƚĞĂŵĚƵƌŝŶŐƚŚĞĚĞǀĞůŽƉŵĞŶƚŽĨƚŚĞƐƚĂŶĚĂƌĚĂŶĚǁŝůů
ďĞƌĞŵŽǀĞĚǁŚĞŶƚŚĞƐƚĂŶĚĂƌĚďĞĐŽŵĞƐĞĨĨĞĐƚŝǀĞ͘
ĞǀĞůŽƉŵĞŶƚ^ƚĞƉƐŽŵƉůĞƚĞĚ͗
ϭ͘ dŚĞ^ZĨŽƌWƌŽũĞĐƚϮϬϬϳͲϭϴ͕ZĞůŝĂďŝůŝƚLJĂƐĞĚŽŶƚƌŽůƐ͕ǁĂƐƉŽƐƚĞĚĨŽƌĂϯϬͲĚĂLJĨŽƌŵĂů
ĐŽŵŵĞŶƚƉĞƌŝŽĚŽŶDĂLJϭϱ͕ϮϬϬϳ͘
Ϯ͘ ƌĞǀŝƐĞĚ^ZĨŽƌWƌŽũĞĐƚϮϬϬϳͲϬϱ͕ZĞůŝĂďŝůŝƚLJĂƐĞĚŽŶƚƌŽůƐ͕ǁĂƐƉŽƐƚĞĚĨŽƌĂƐĞĐŽŶĚ
ϯϬͲĚĂLJĨŽƌŵĂůĐŽŵŵĞŶƚƉĞƌŝŽĚŽŶ^ĞƉƚĞŵďĞƌϭϬ͕ϮϬϬϳ͘
ϯ͘ dŚĞ^ƚĂŶĚĂƌĚƐŽŵŵŝƚƚĞĞĂƉƉƌŽǀĞĚWƌŽũĞĐƚϮϬϬϳͲϭϴ͕ZĞůŝĂďŝůŝƚLJĂƐĞĚŽŶƚƌŽůƐ͕ƚŽďĞ
ŵŽǀĞĚƚŽƐƚĂŶĚĂƌĚĚƌĂĨƚŝŶŐŽŶĞĐĞŵďĞƌϭϭ͕ϮϬϬϳ͘
ϰ͘ dŚĞ^ZĨŽƌWƌŽũĞĐƚϮϬϬϳͲϬϱ͕ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJŽŶƚƌŽůƐ͕ǁĂƐƉŽƐƚĞĚĨŽƌĂϯϬͲĚĂLJ
ĨŽƌŵĂůĐŽŵŵĞŶƚƉĞƌŝŽĚŽŶ:ƵůLJϯ͕ϮϬϬϳ͘
ϱ͘ dŚĞ^ƚĂŶĚĂƌĚƐŽŵŵŝƚƚĞĞĂƉƉƌŽǀĞĚWƌŽũĞĐƚϮϬϬϳͲϬϱ͕ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJŽŶƚƌŽůƐ͕ƚŽ
ďĞŵŽǀĞĚƚŽƐƚĂŶĚĂƌĚĚƌĂĨƚŝŶŐŽŶ:ĂŶƵĂƌLJϭϴ͕ϮϬϬϴ͘
ϲ͘ dŚĞ^ƚĂŶĚĂƌĚƐŽŵŵŝƚƚĞĞĂƉƉƌŽǀĞĚƚŚĞŵĞƌŐĞƌŽĨWƌŽũĞĐƚϮϬϬϳͲϬϱ͕ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ
ŽŶƚƌŽůƐ͕ĂŶĚWƌŽũĞĐƚϮϬϬϳͲϭϴ͕ZĞůŝĂďŝůŝƚLJͲďĂƐĞĚŽŶƚƌŽůƐ͕ĂƐWƌŽũĞĐƚϮϬϭϬͲϭϰ͕ĂůĂŶĐŝŶŐ
ƵƚŚŽƌŝƚLJZĞůŝĂďŝůŝƚLJͲďĂƐĞĚŽŶƚƌŽůƐ͕ŽŶ:ƵůLJϮϴ͕ϮϬϭϬ͘
ϳ͘ dŚĞEZ^ƚĂŶĚĂƌĚƐŽŵŵŝƚƚĞĞĂƉƉƌŽǀĞĚďƌĞĂŬŝŶŐWƌŽũĞĐƚϮϬϭϬͲϭϰ͕ĂůĂŶĐŝŶŐ
ƵƚŚŽƌŝƚLJZĞůŝĂďŝůŝƚLJͲďĂƐĞĚŽŶƚƌŽůƐ͕ŝŶƚŽƚǁŽƉŚĂƐĞƐ͖ĂŶĚŵŽǀŝŶŐWŚĂƐĞϭ;WƌŽũĞĐƚϮϬϭϬͲ
ϭϰ͘ϭ͕ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJZĞůŝĂďŝůŝƚLJͲďĂƐĞĚŽŶƚƌŽůƐʹZĞƐĞƌǀĞƐͿŝŶƚŽĨŽƌŵĂůƐƚĂŶĚĂƌĚƐ
ĚĞǀĞůŽƉŵĞŶƚŽŶ:ƵůLJϭϯ͕ϮϬϭϭ͘
ϴ͘ dŚĞĚƌĂĨƚƐƚĂŶĚĂƌĚǁĂƐƉŽƐƚĞĚĨŽƌϯϬͲĚĂLJĨŽƌŵĂůŝŶĚƵƐƚƌLJĐŽŵŵĞŶƚƉĞƌŝŽĚĨƌŽŵ:ƵŶĞϰ͕
ϮϬϭϮƚŚƌŽƵŐŚ:ƵůLJϯ͕ϮϬϭϮ͘
ϵ͘ dŚĞĚƌĂĨƚƐƚĂŶĚĂƌĚǁĂƐƉŽƐƚĞĚĨŽƌĂϰϱͲĚĂLJĨŽƌŵĂůŝŶĚƵƐƚƌLJĐŽŵŵĞŶƚƉĞƌŝŽĚĂŶĚŝŶŝƚŝĂů
ďĂůůŽƚĨƌŽŵDĂƌĐŚϭϮ͕ϮϬϭϯƚŚƌŽƵŐŚƉƌŝůϮϱ͕ϮϬϭϯ͘
WƌŽƉŽƐĞĚĐƚŝŽŶWůĂŶĂŶĚĞƐĐƌŝƉƚŝŽŶŽĨƵƌƌĞŶƚƌĂĨƚ͗
dŚŝƐŝƐƚŚĞƐĞĐŽŶĚƉŽƐƚŝŶŐŽĨƚŚĞƉƌŽƉŽƐĞĚŶĞǁƐƚĂŶĚĂƌĚ͘dŚŝƐƉƌŽƉŽƐĞĚĚƌĂĨƚƐƚĂŶĚĂƌĚǁŝůůďĞ
ƉŽƐƚĞĚĨŽƌĂϭϬͲĚĂLJƌĞͲĐŝƌĐƵůĂƚŝŽŶďĂůůŽƚĨƌŽŵ:ƵůLJyy͕ϮϬϭϯƚŚƌŽƵŐŚ:ƵůLJyy͕ϮϬϭϯ͘

&ƵƚƵƌĞĞǀĞůŽƉŵĞŶƚWůĂŶ͗
ŶƚŝĐŝƉĂƚĞĚĐƚŝŽŶƐ

ŶƚŝĐŝƉĂƚĞĚĂƚĞ

ϭ͘ ZĞĐŝƌĐƵůĂƚŝŽŶĂůůŽƚ

:ƵůLJϮϬϭϯ

Ϯ͘ EZKdĂĚŽƉƚŝŽŶ͘

ƵŐƵƐƚϮϬϭϯ

>ͲϬϬϭͲϮ
:ƵůLJ͕ϮϬϭϯ



WĂŐĞϭŽĨϭϯ



^ƚĂŶĚĂƌĚ>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
ĞĨŝŶŝƚŝŽŶƐŽĨdĞƌŵƐhƐĞĚŝŶ^ƚĂŶĚĂƌĚ
dŚŝƐƐĞĐƚŝŽŶŝŶĐůƵĚĞƐĂůůŶĞǁůLJĚĞĨŝŶĞĚŽƌƌĞǀŝƐĞĚƚĞƌŵƐƵƐĞĚŝŶƚŚĞƉƌŽƉŽƐĞĚƐƚĂŶĚĂƌĚ͘dĞƌŵƐ
ĂůƌĞĂĚLJĚĞĨŝŶĞĚŝŶƚŚĞZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚƐ'ůŽƐƐĂƌLJŽĨdĞƌŵƐĂƌĞŶŽƚƌĞƉĞĂƚĞĚŚĞƌĞ͘EĞǁŽƌ
ƌĞǀŝƐĞĚĚĞĨŝŶŝƚŝŽŶƐůŝƐƚĞĚďĞůŽǁďĞĐŽŵĞĂƉƉƌŽǀĞĚǁŚĞŶƚŚĞƉƌŽƉŽƐĞĚƐƚĂŶĚĂƌĚŝƐĂƉƉƌŽǀĞĚ͘
tŚĞŶƚŚĞƐƚĂŶĚĂƌĚďĞĐŽŵĞƐĞĨĨĞĐƚŝǀĞ͕ƚŚĞƐĞĚĞĨŝŶĞĚƚĞƌŵƐǁŝůůďĞƌĞŵŽǀĞĚĨƌŽŵƚŚĞŝŶĚŝǀŝĚƵĂů
ƐƚĂŶĚĂƌĚĂŶĚĂĚĚĞĚƚŽƚŚĞ'ůŽƐƐĂƌLJ͘
ZĞŐƵůĂƚŝŽŶZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ͗ŐƌŽƵƉǁŚŽƐĞŵĞŵďĞƌƐĐŽŶƐŝƐƚŽĨƚǁŽŽƌŵŽƌĞĂůĂŶĐŝŶŐ
ƵƚŚŽƌŝƚŝĞƐƚŚĂƚĐŽůůĞĐƚŝǀĞůLJŵĂŝŶƚĂŝŶ͕ĂůůŽĐĂƚĞ͕ĂŶĚƐƵƉƉůLJƚŚĞZƌĞŐƵůĂƚŝŶŐZƌĞƐĞƌǀĞƌĞƋƵŝƌĞĚĨŽƌ
ĂůůŵĞŵďĞƌĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐƚŽƵƐĞŝŶŵĞĞƚŝŶŐĂƉƉůŝĐĂďůĞƌĞŐƵůĂƚŝŶŐƐƚĂŶĚĂƌĚƐ͘
ZĞŐƵůĂƚŝŽŶZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉZĞƉŽƌƚŝŶŐ͗ƚĂŶLJŐŝǀĞŶƚŝŵĞŽĨŵĞĂƐƵƌĞŵĞŶƚĨŽƌƚŚĞ
ĂƉƉůŝĐĂďůĞZĞŐƵůĂƚŝŽŶZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ͕ƚŚĞĂůŐĞďƌĂŝĐƐƵŵŽĨƚŚĞZĞƉŽƌƚŝŶŐƐ;Žƌ
ĞƋƵŝǀĂůĞŶƚĂƐĐĂůĐƵůĂƚĞĚĂƚƐƵĐŚƚŝŵĞŽĨŵĞĂƐƵƌĞŵĞŶƚͿŽĨƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐ
ƉĂƌƚŝĐŝƉĂƚŝŶŐŝŶƚŚĞZĞŐƵůĂƚŝŽŶZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉĂƚƚŚĞƚŝŵĞŽĨŵĞĂƐƵƌĞŵĞŶƚ͘
ZĞƉŽƌƚŝŶŐ͗dŚĞƐĐĂŶƌĂƚĞǀĂůƵĞƐŽĨĂĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛ƐƌĞĂŽŶƚƌŽůƌƌŽƌ;Ϳ
ŵĞĂƐƵƌĞĚŝŶDt͕ǁŚŝĐŚŝŶĐůƵĚĞƐƚŚĞĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛ƐEŶĞƚ
ĂĐƚƵĂů/ŶƚĞƌĐŚĂŶŐĞĂŶĚŝƚƐEĞƚ^ƐĐŚĞĚƵůĞĚ//ŶƚĞƌĐŚĂŶŐĞ͕ƉůƵƐŝƚƐ&ƌĞƋƵĞŶĐLJŝĂƐŽďůŝŐĂƚŝŽŶ͕
ƉůƵƐĂŶLJŬŶŽǁŶŵĞƚĞƌĞƌƌŽƌƉůƵƐƵƚŽŵĂƚŝĐdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶ;dʹ/ĨŽƉĞƌĂƚŝŶŐŝŶƚŚĞ
tĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶĂŶĚŝŶƚŚĞdŵŽĚĞͿ͘/ŶƚŚĞtĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͕ZĞƉŽƌƚŝŶŐ
ŝŶĐůƵĚĞƐƵƚŽŵĂƚŝĐdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶ;dͿ͘
ZĞƉŽƌƚŝŶŐŝƐĐĂůĐƵůĂƚĞĚĂƐĨŽůůŽǁƐ͗


ZĞƉŽƌƚŝŶŐс;E/оE/^ͿоϭϬ;&о&^Ϳо/Dн/d
ZĞƉŽƌƚŝŶŐŝƐĐĂůĐƵůĂƚĞĚŝŶƚŚĞtĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶĂƐĨŽůůŽǁƐ͗



ZĞƉŽƌƚŝŶŐс;E/оE/^ͿоϭϬ;&о&^Ϳо/Dн/d


tŚĞƌĞ͗
E/;ĐƚƵĂůEĞƚ/ŶƚĞƌĐŚĂŶŐĞͿŝƐƚŚĞĂůŐĞďƌĂŝĐƐƵŵŽĨĂĐƚƵĂůŵĞŐĂǁĂƚƚƚƌĂŶƐĨĞƌƐĂĐƌŽƐƐĂůů
dŝĞ>ŝŶĞƐĂŶĚŝŶĐůƵĚĞƐWƐĞƵĚŽͲdŝĞƐ͘ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐĚŝƌĞĐƚůLJĐŽŶŶĞĐƚĞĚǀŝĂ
ĂƐLJŶĐŚƌŽŶŽƵƐƚŝĞƐƚŽĂŶŽƚŚĞƌ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶŵĂLJŝŶĐůƵĚĞŽƌĞdžĐůƵĚĞŵĞŐĂǁĂƚƚ
ƚƌĂŶƐĨĞƌƐŽŶƚŚŽƐĞdƚŝĞ>ůŝŶĞƐŝŶƚŚĞŝƌĂĐƚƵĂůŝŶƚĞƌĐŚĂŶŐĞ͕ƉƌŽǀŝĚĞĚƚŚĞLJĂƌĞ
ŝŵƉůĞŵĞŶƚĞĚŝŶƚŚĞƐĂŵĞŵĂŶŶĞƌĨŽƌEĞƚ/ŶƚĞƌĐŚĂŶŐĞ^ĐŚĞĚƵůĞ͘
E/^;^ĐŚĞĚƵůĞĚEĞƚ/ŶƚĞƌĐŚĂŶŐĞͿŝƐƚŚĞĂůŐĞďƌĂŝĐƐƵŵŽĨĂůůƐĐŚĞĚƵůĞĚŵĞŐĂǁĂƚƚ
ƚƌĂŶƐĨĞƌƐ͕ŝŶĐůƵĚŝŶŐLJŶĂŵŝĐ^ĐŚĞĚƵůĞƐ͕ǁŝƚŚĂĚũĂĐĞŶƚĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐ͕ĂŶĚƚĂŬŝŶŐ
ŝŶƚŽĂĐĐŽƵŶƚƚŚĞĞĨĨĞĐƚƐŽĨƐĐŚĞĚƵůĞƌĂŵƉƐ͘ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐĚŝƌĞĐƚůLJĐŽŶŶĞĐƚĞĚǀŝĂ
ĂƐLJŶĐŚƌŽŶŽƵƐƚŝĞƐƚŽĂŶŽƚŚĞƌ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶŵĂLJŝŶĐůƵĚĞŽƌĞdžĐůƵĚĞŵĞŐĂǁĂƚƚ
ƚƌĂŶƐĨĞƌƐŽŶƚŚŽƐĞdƚŝĞ>ůŝŶĞƐŝŶƚŚĞŝƌƐĐŚĞĚƵůĞĚ/ŶƚĞƌĐŚĂŶŐĞ͕ƉƌŽǀŝĚĞĚƚŚĞLJĂƌĞ
ŝŵƉůĞŵĞŶƚĞĚŝŶƚŚĞƐĂŵĞŵĂŶŶĞƌĨŽƌEĞƚ/ŶƚĞƌĐŚĂŶŐĞĐƚƵĂů͘
;&ƌĞƋƵĞŶĐLJŝĂƐ^ĞƚƚŝŶŐͿŝƐƚŚĞ&ƌĞƋƵĞŶĐLJŝĂƐ^ĞƚƚŝŶŐ;ŝŶŶĞŐĂƚŝǀĞDtͬϬ͘ϭ,njͿĨŽƌƚŚĞ
ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͘

>ͲϬϬϭͲϮ
:ƵůLJ͕ϮϬϭϯ



WĂŐĞϮŽĨϭϯ



^ƚĂŶĚĂƌĚ>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
ϭϬŝƐƚŚĞĐŽŶƐƚĂŶƚĨĂĐƚŽƌƚŚĂƚĐŽŶǀĞƌƚƐƚŚĞ&ĨƌĞƋƵĞŶĐLJďŝĂƐ^ƐĞƚƚŝŶŐƵŶŝƚƐƚŽDtͬ,nj͘
&;ĐƚƵĂů&ƌĞƋƵĞŶĐLJͿŝƐƚŚĞŵĞĂƐƵƌĞĚĨƌĞƋƵĞŶĐLJŝŶ,nj͘
&^;^ĐŚĞĚƵůĞĚ&ƌĞƋƵĞŶĐLJͿŝƐϲϬ͘Ϭ,nj͕ĞdžĐĞƉƚĚƵƌŝŶŐĂƚŝŵĞĐŽƌƌĞĐƚŝŽŶ͘
/D;/ŶƚĞƌĐŚĂŶŐĞDĞƚĞƌƌƌŽƌͿŝƐƚŚĞŵĞƚĞƌĞƌƌŽƌĐŽƌƌĞĐƚŝŽŶĨĂĐƚŽƌĂŶĚƌĞƉƌĞƐĞŶƚƐƚŚĞ
ĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶƚŚĞŝŶƚĞŐƌĂƚĞĚŚŽƵƌůLJĂǀĞƌĂŐĞŽĨƚŚĞŶĞƚŝŶƚĞƌĐŚĂŶŐĞĂĐƚƵĂů;E/Ϳ
ĂŶĚƚŚĞĐƵŵƵůĂƚŝǀĞŚŽƵƌůLJŶĞƚŝ/ŶƚĞƌĐŚĂŶŐĞĞŶĞƌŐLJŵĞĂƐƵƌĞŵĞŶƚ;ŝŶŵĞŐĂǁĂƚƚͲŚŽƵƌƐͿ͘
/d;ƵƚŽŵĂƚŝĐdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶͿŝƐƚŚĞĂĚĚŝƚŝŽŶŽĨĂĐŽŵƉŽŶĞŶƚƚŽƚŚĞ
ĞƋƵĂƚŝŽŶĨŽƌƚŚĞtĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶƚŚĂƚŵŽĚŝĨŝĞƐƚŚĞĐŽŶƚƌŽůƉŽŝŶƚĨŽƌƚŚĞ
ƉƵƌƉŽƐĞŽĨĐŽŶƚŝŶƵŽƵƐůLJƉĂLJŝŶŐďĂĐŬWƌŝŵĂƌLJ/ŶĂĚǀĞƌƚĞŶƚ/ŶƚĞƌĐŚĂŶŐĞƚŽĐŽƌƌĞĐƚ
ĂĐĐƵŵƵůĂƚĞĚƚŝŵĞĞƌƌŽƌ͘ƵƚŽŵĂƚŝĐdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶŝƐŽŶůLJĂƉƉůŝĐĂďůĞŝŶƚŚĞ
tĞƐƚĞƌŶ/ŝŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͘
on/off peak

IATEC

= PII

accum

(1 − Y )* H

ǁŚĞŶŽƉĞƌĂƚŝŶŐŝŶƵƚŽŵĂƚŝĐdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶĐŽŶƚƌŽůŵŽĚĞ͘

/dƐŚĂůůďĞnjĞƌŽǁŚĞŶŽƉĞƌĂƚŝŶŐŝŶĂŶLJŽƚŚĞƌ'ŵŽĚĞ͘
•

zсͬ^͘

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,сEƵŵďĞƌŽĨŚ,ŽƵƌƐƵƐĞĚƚŽƉĂLJďĂĐŬWƌŝŵĂƌLJ/ŶĂĚǀĞƌƚĞŶƚ/ŶƚĞƌĐŚĂŶŐĞĞŶĞƌŐLJ͘dŚĞ
ǀĂůƵĞŽĨ,ŝƐƐĞƚƚŽϯ͘

•

^с&ƌĞƋƵĞŶĐLJŝĂƐĨŽƌƚŚĞ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ;DtͬϬ͘ϭ,njͿ͘

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WƌŝŵĂƌLJ/ŶĂĚǀĞƌƚĞŶƚ/ŶƚĞƌĐŚĂŶŐĞ;W//ŚŽƵƌůLJͿŝƐ;ϭͲzͿΎ;//ĂĐƚƵĂůͲΎȴdͬϲͿ

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//ĂĐƚƵĂůŝƐƚŚĞŚŽƵƌůLJ/ŶĂĚǀĞƌƚĞŶƚ/ŶƚĞƌĐŚĂŶŐĞĨŽƌƚŚĞůĂƐƚŚŽƵƌ͘

•

ȴdŝƐƚŚĞŚŽƵƌůLJĐŚĂŶŐĞŝŶƐLJƐƚĞŵdŝŵĞƌƌŽƌĂƐĚŝƐƚƌŝďƵƚĞĚďLJƚŚĞ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ
dŝŵĞDŽŶŝƚŽƌ͘tŚĞƌĞ͗



ȴdсdĞŶĚŚŽƵƌʹdďĞŐŝŶŚŽƵƌʹdĂĚũʹ;ƚͿΎ;dŽĨĨƐĞƚͿ

•

dĂĚũŝƐƚŚĞZĞůŝĂďŝůŝƚLJŽŽƌĚŝŶĂƚŽƌĂĚũƵƐƚŵĞŶƚĨŽƌĚŝĨĨĞƌĞŶĐĞƐǁŝƚŚ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ
dŝŵĞDŽŶŝƚŽƌĐŽŶƚƌŽůĐĞŶƚĞƌĐůŽĐŬƐ͘

•

ƚŝƐƚŚĞŶƵŵďĞƌŽĨŵŝŶƵƚĞƐŽĨDĂŶƵĂůdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶƚŚĂƚŽĐĐƵƌƌĞĚĚƵƌŝŶŐƚŚĞ
ŚŽƵƌ͘

•

dŽĨĨƐĞƚŝƐϬ͘ϬϬϬŽƌнϬ͘ϬϮϬŽƌͲϬ͘ϬϮϬ͘

•

W//ĂĐĐƵŵŝƐƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛ƐĂĐĐƵŵƵůĂƚĞĚW//ŚŽƵƌůLJŝŶDtŚ͘ŶKŶͲWĞĂŬĂŶĚ
KĨĨͲWĞĂŬĂĐĐƵŵƵůĂƚŝŽŶĂĐĐŽƵŶƚŝŶŐŝƐƌĞƋƵŝƌĞĚ͘
tŚĞƌĞ͗

PII

on/off peak
accum

сůĂƐƚƉĞƌŝŽĚ͛Ɛ

on/off peak

PII

accum

нW//ŚŽƵƌůLJ



>ͲϬϬϭͲϮ
:ƵůLJ͕ϮϬϭϯ



WĂŐĞϯŽĨϭϯ



^ƚĂŶĚĂƌĚ>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
ůůEZ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶƐǁŝƚŚŵƵůƚŝƉůĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐŽƉĞƌĂƚĞƵƐŝŶŐƚŚĞƉƌŝŶĐŝƉůĞƐ
ŽĨdŝĞͲůŝŶĞŝĂƐ;d>ͿŽŶƚƌŽůĂŶĚƌĞƋƵŝƌĞƚŚĞƵƐĞŽĨĂŶĞƋƵĂƚŝŽŶƐŝŵŝůĂƌƚŽƚŚĞ
ZĞƉŽƌƚŝŶŐĚĞĨŝŶĞĚĂďŽǀĞ͘ŶLJŵŽĚŝĨŝĐĂƚŝŽŶ;ƐͿƚŽƚŚŝƐƐƉĞĐŝĨŝĞĚZĞƉŽƌƚŝŶŐ
ĞƋƵĂƚŝŽŶƚŚĂƚŝƐ;ĂƌĞͿŝŵƉůĞŵĞŶƚĞĚĨŽƌĂůůƐŽŶĂŶ/ŝŶƚĞƌĐŽŶŶĞĐƚŝŽŶĂŶĚŝƐ;ĂƌĞͿĐŽŶƐŝƐƚĞŶƚ
ǁŝƚŚƚŚĞĨŽůůŽǁŝŶŐĨŽƵƌƉƌŝŶĐŝƉůĞƐǁŝůůƉƌŽǀŝĚĞĂǀĂůŝĚĂůƚĞƌŶĂƚŝǀĞZĞƉŽƌƚŝŶŐĞƋƵĂƚŝŽŶ
ĐŽŶƐŝƐƚĞŶƚǁŝƚŚƚŚĞŵĞĂƐƵƌĞƐŝŶĐůƵĚĞĚŝŶƚŚŝƐƐƚĂŶĚĂƌĚ͘
ϭ͘ ůůƉŽƌƚŝŽŶƐŽĨƚŚĞ/ŝŶƚĞƌĐŽŶŶĞĐƚŝŽŶĂƌĞŝŶĐůƵĚĞĚŝŶŽŶĞĂƌĞĂŽƌĂŶŽƚŚĞƌƐŽƚŚĂƚ
ƚŚĞƐƵŵŽĨĂůůĂƌĞĂŐĞŶĞƌĂƚŝŽŶ͕ůŽĂĚƐĂŶĚůŽƐƐĞƐŝƐƚŚĞƐĂŵĞĂƐƚŽƚĂůƐLJƐƚĞŵ
ŐĞŶĞƌĂƚŝŽŶ͕ůŽĂĚĂŶĚůŽƐƐĞƐ͘
Ϯ͘ dŚĞĂůŐĞďƌĂŝĐƐƵŵŽĨĂůůĂƌĞĂEŶĞƚ/ŝŶƚĞƌĐŚĂŶŐĞ^ƐĐŚĞĚƵůĞƐĂŶĚĂůůEŶĞƚ
/ŝŶƚĞƌĐŚĂŶŐĞĂĐƚƵĂůǀĂůƵĞƐŝƐĞƋƵĂůƚŽnjĞƌŽĂƚĂůůƚŝŵĞƐ͘
ϯ͘ dŚĞƵƐĞŽĨĂĐŽŵŵŽŶ^ƐĐŚĞĚƵůĞĚ&ĨƌĞƋƵĞŶĐLJ&^ĨŽƌĂůůĂƌĞĂƐĂƚĂůůƚŝŵĞƐ͘
ϰ͘ dŚĞĂďƐĞŶĐĞŽĨŵĞƚĞƌŝŶŐŽƌĐŽŵƉƵƚĂƚŝŽŶĂůĞƌƌŽƌƐ͘;dŚĞŝŶĐůƵƐŝŽŶĂŶĚƵƐĞŽĨƚŚĞ
/DƚĞƌŵƚŽĂĐĐŽƵŶƚĨŽƌŬŶŽǁŶŵĞƚĞƌŝŶŐŽƌĐŽŵƉƵƚĂƚŝŽŶĂůĞƌƌŽƌƐ͘Ϳ

/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͗tŚĞŶĐĂƉŝƚĂůŝnjĞĚ͕ĂŶLJŽŶĞŽĨƚŚĞĨŽƵƌŵĂũŽƌĞůĞĐƚƌŝĐƐLJƐƚĞŵŶĞƚǁŽƌŬƐŝŶEŽƌƚŚ
ŵĞƌŝĐĂ͗ĂƐƚĞƌŶ͕tĞƐƚĞƌŶ͕ZKdĂŶĚYƵĞďĞĐ͘ 


>ͲϬϬϭͲϮ
:ƵůLJ͕ϮϬϭϯ



WĂŐĞϰŽĨϭϯ



^ƚĂŶĚĂƌĚ>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
A. Introduction
ϭ͘

dŝƚůĞ͗

ZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ

Ϯ͘

EƵŵďĞƌ͗

>ͲϬϬϭͲϮ

ϯ͘

WƵƌƉŽƐĞ͗

dŽĐŽŶƚƌŽů/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶĨƌĞƋƵĞŶĐLJǁŝƚŚŝŶĚĞĨŝŶĞĚůŝŵŝƚƐ͘

ϰ͘

ƉƉůŝĐĂďŝůŝƚLJ͗
ϰ͘ϭ͘ ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ
ϰ͘ϭ͘ϭ ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJƌĞĐĞŝǀŝŶŐKǀĞƌůĂƉZĞŐƵůĂƚŝŽŶ^ĞƌǀŝĐĞŝƐŶŽƚƐƵďũĞĐƚ
ƚŽŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ^ƚĂŶĚĂƌĚϭ;W^ϭͿŽƌĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ
>ŝŵŝƚ;>ͿĐŽŵƉůŝĂŶĐĞĞǀĂůƵĂƚŝŽŶ͘
ϰ͘ϭ͘Ϯ ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJƚŚĂƚŝƐĂŵĞŵďĞƌŽĨĂZĞŐƵůĂƚŝŽŶZĞƐĞƌǀĞ^ŚĂƌŝŶŐ
'ƌŽƵƉŝƐƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJŽŶůLJŝŶƉĞƌŝŽĚƐĚƵƌŝŶŐǁŚŝĐŚƚŚĞ
ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJŝƐŶŽƚŝŶĂĐƚŝǀĞƐƚĂƚƵƐƵŶĚĞƌƚŚĞĂƉƉůŝĐĂďůĞ
ĂŐƌĞĞŵĞŶƚŽƌƚŚĞŐŽǀĞƌŶŝŶŐƌƵůĞƐĨŽƌƚŚĞZĞŐƵůĂƚŝŽŶZĞƐĞƌǀĞ^ŚĂƌŝŶŐ
'ƌŽƵƉ͘
ϰ͘Ϯ͘ ZĞŐƵůĂƚŝŽŶZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ

ϱ͘

;WƌŽƉŽƐĞĚͿĨĨĞĐƚŝǀĞĂƚĞ͗
ϱ͘ϭ͘



&ŝƌƐƚĚĂLJŽĨƚŚĞĨŝƌƐƚĐĂůĞŶĚĂƌƋƵĂƌƚĞƌƚŚĂƚŝƐƚǁĞůǀĞƐŝdžŵŽŶƚŚƐďĞLJŽŶĚƚŚĞĚĂƚĞ
ƚŚĂƚƚŚŝƐƐƚĂŶĚĂƌĚŝƐĂƉƉƌŽǀĞĚďLJĂƉƉůŝĐĂďůĞƌĞŐƵůĂƚŽƌLJĂƵƚŚŽƌŝƚŝĞƐ͕ŽƌŝŶƚŚŽƐĞ
ũƵƌŝƐĚŝĐƚŝŽŶƐǁŚĞƌĞƌĞŐƵůĂƚŽƌLJĂƉƉƌŽǀĂůŝƐŶŽƚƌĞƋƵŝƌĞĚ͕ƚŚĞƐƚĂŶĚĂƌĚďĞĐŽŵĞƐ
ĞĨĨĞĐƚŝǀĞƚŚĞĨŝƌƐƚĚĂLJŽĨƚŚĞĨŝƌƐƚĐĂůĞŶĚĂƌƋƵĂƌƚĞƌƚŚĂƚŝƐƚǁĞůǀĞƐŝdžŵŽŶƚŚƐ
ďĞLJŽŶĚƚŚĞĚĂƚĞƚŚŝƐƐƚĂŶĚĂƌĚŝƐĂƉƉƌŽǀĞĚďLJƚŚĞEZŽĂƌĚŽĨdƌƵƐƚĞĞƐ͕͛Žƌ
ĂƐŽƚŚĞƌǁŝƐĞŵĂĚĞĞĨĨĞĐƚŝǀĞƉƵƌƐƵĂŶƚƚŽƚŚĞůĂǁƐĂƉƉůŝĐĂďůĞƚŽƐƵĐŚZK
ŐŽǀĞƌŶŵĞŶƚĂůĂƵƚŚŽƌŝƚŝĞƐ͘ 


B. ZĞƋƵŝƌĞŵĞŶƚƐ
Zϭ͘

dŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJƐŚĂůůŽƉĞƌĂƚĞƐƵĐŚƚŚĂƚƚŚĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ^ƚĂŶĚĂƌĚϭ
;W^ϭͿ͕ĐĂůĐƵůĂƚĞĚŝŶĂĐĐŽƌĚĂŶĐĞǁŝƚŚƚƚĂĐŚŵĞŶƚϭ͕ŝƐŐƌĞĂƚĞƌƚŚĂŶŽƌĞƋƵĂůƚŽϭϬϬ
ƉĞƌĐĞŶƚĨŽƌƚŚĞĂƉƉůŝĐĂďůĞ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶŝŶǁŚŝĐŚŝƚŽƉĞƌĂƚĞƐĨŽƌĞĂĐŚƉƌĞĐĞĚŝŶŐϭϮ
ĐŽŶƐĞĐƵƚŝǀĞĐĂůĞŶĚĂƌͲŵŽŶƚŚƉĞƌŝŽĚ͕ĞǀĂůƵĂƚĞĚŵŽŶƚŚůLJ͘΀sŝŽůĂƚŝŽŶZŝƐŬ&ĂĐƚŽƌ͗
DĞĚŝƵŵ΁΀dŝŵĞ,ŽƌŝnjŽŶ͗ZĞĂůͲƚŝŵĞKƉĞƌĂƚŝŽŶƐ΁

ZϮ͘

ĂĐŚĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJƐŚĂůůŽƉĞƌĂƚĞƐƵĐŚƚŚĂƚŝƚƐĐůŽĐŬͲŵŝŶƵƚĞĂǀĞƌĂŐĞŽĨZĞƉŽƌƚŝŶŐ
ĚŽĞƐŶŽƚĞdžĐĞĞĚŝƚƐĐůŽĐŬͲŵŝŶƵƚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ>ŝŵŝƚ;>ͿĨŽƌŵŽƌĞ
ƚŚĂŶϯϬĐŽŶƐĞĐƵƚŝǀĞĐůŽĐŬͲŵŝŶƵƚĞƐ͕ĂƐĐĂůĐƵůĂƚĞĚŝŶĂĐĐŽƌĚĂŶĐĞǁŝƚŚƚƚĂĐŚŵĞŶƚϮ͕
ĨŽƌƚŚĞĂƉƉůŝĐĂďůĞ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶŝŶǁŚŝĐŚƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ
ŽƉĞƌĂƚĞƐ͘΀sŝŽůĂƚŝŽŶZŝƐŬ&ĂĐƚŽƌ͗DĞĚŝƵŵ΁΀dŝŵĞ,ŽƌŝnjŽŶ͗ZĞĂůͲƚŝŵĞKƉĞƌĂƚŝŽŶƐ΁

C. DĞĂƐƵƌĞƐ
Dϭ͘ dŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJƐŚĂůůƉƌŽǀŝĚĞĞǀŝĚĞŶĐĞ͕ƵƉŽŶƌĞƋƵĞƐƚ͕ƐƵĐŚĂƐĚĂƚĞĚĐĂůĐƵůĂƚŝŽŶ
ŽƵƚƉƵƚĨƌŽŵƐƉƌĞĂĚƐŚĞĞƚƐ͕ŶĞƌŐLJDĂŶĂŐĞŵĞŶƚƐ^LJƐƚĞŵůŽŐƐ͕ƐŽĨƚǁĂƌĞƉƌŽŐƌĂŵƐ͕Žƌ

>ͲϬϬϭͲϮ
:ƵůLJ͕ϮϬϭϯ



WĂŐĞϱŽĨϭϯ



^ƚĂŶĚĂƌĚ>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
ŽƚŚĞƌĞǀŝĚĞŶĐĞ;ĞŝƚŚĞƌŝŶŚĂƌĚĐŽƉLJŽƌĞůĞĐƚƌŽŶŝĐĨŽƌŵĂƚͿƚŽĚĞŵŽŶƐƚƌĂƚĞĐŽŵƉůŝĂŶĐĞ
ǁŝƚŚZĞƋƵŝƌĞŵĞŶƚZϭ͘
DϮ͘ ĂĐŚĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJƐŚĂůůƉƌŽǀŝĚĞĞǀŝĚĞŶĐĞ͕ƵƉŽŶƌĞƋƵĞƐƚ͕ƐƵĐŚĂƐĚĂƚĞĚ
ĐĂůĐƵůĂƚŝŽŶŽƵƚƉƵƚĨƌŽŵƐƉƌĞĂĚƐŚĞĞƚƐ͕ŶĞƌŐLJDĂŶĂŐĞŵĞŶƚƐ^LJƐƚĞŵůŽŐƐ͕ƐŽĨƚǁĂƌĞ
ƉƌŽŐƌĂŵƐ͕ŽƌŽƚŚĞƌĞǀŝĚĞŶĐĞ;ĞŝƚŚĞƌŝŶŚĂƌĚĐŽƉLJŽƌĞůĞĐƚƌŽŶŝĐĨŽƌŵĂƚͿƚŽĚĞŵŽŶƐƚƌĂƚĞ
ĐŽŵƉůŝĂŶĐĞǁŝƚŚZĞƋƵŝƌĞŵĞŶƚZϮ͘
D. ŽŵƉůŝĂŶĐĞ
ϭ͘

ŽŵƉůŝĂŶĐĞDŽŶŝƚŽƌŝŶŐWƌŽĐĞƐƐ
ϭ͘ϭ͘ ŽŵƉůŝĂŶĐĞŶĨŽƌĐĞŵĞŶƚƵƚŚŽƌŝƚLJ
ƐĚĞĨŝŶĞĚŝŶƚŚĞEZZƵůĞƐŽĨWƌŽĐĞĚƵƌĞ͕͞ŽŵƉůŝĂŶĐĞŶĨŽƌĐĞŵĞŶƚƵƚŚŽƌŝƚLJ͟
ŵĞĂŶƐEZŽƌƚŚĞZĞŐŝŽŶĂůŶƚŝƚLJŝŶƚŚĞŝƌƌĞƐƉĞĐƚŝǀĞƌŽůĞƐŽĨŵŽŶŝƚŽƌŝŶŐĂŶĚ
ĞŶĨŽƌĐŝŶŐĐŽŵƉůŝĂŶĐĞǁŝƚŚƚŚĞEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚƐ͘
ϭ͘Ϯ͘ ĂƚĂZĞƚĞŶƚŝŽŶ
dŚĞĨŽůůŽǁŝŶŐĞǀŝĚĞŶĐĞƌĞƚĞŶƚŝŽŶƉĞƌŝŽĚƐŝĚĞŶƚŝĨLJƚŚĞƉĞƌŝŽĚŽĨƚŝŵĞĂŶĞŶƚŝƚLJŝƐ
ƌĞƋƵŝƌĞĚƚŽƌĞƚĂŝŶƐƉĞĐŝĨŝĐĞǀŝĚĞŶĐĞƚŽĚĞŵŽŶƐƚƌĂƚĞĐŽŵƉůŝĂŶĐĞ͘&ŽƌŝŶƐƚĂŶĐĞƐ
ǁŚĞƌĞƚŚĞĞǀŝĚĞŶĐĞƌĞƚĞŶƚŝŽŶƉĞƌŝŽĚƐƉĞĐŝĨŝĞĚďĞůŽǁŝƐƐŚŽƌƚĞƌƚŚĂŶƚŚĞƚŝŵĞ
ƐŝŶĐĞƚŚĞůĂƐƚĂƵĚŝƚ͕ƚŚĞĐŽŵƉůŝĂŶĐĞĞŶĨŽƌĐĞŵĞŶƚĂƵƚŚŽƌŝƚLJŵĂLJĂƐŬĂŶĞŶƚŝƚLJ
ƚŽƉƌŽǀŝĚĞŽƚŚĞƌĞǀŝĚĞŶĐĞƚŽƐŚŽǁƚŚĂƚŝƚǁĂƐĐŽŵƉůŝĂŶƚĨŽƌƚŚĞĨƵůůͲƚŝŵĞƉĞƌŝŽĚ
ƐŝŶĐĞƚŚĞůĂƐƚĂƵĚŝƚ͘
dŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJƐŚĂůůƌĞƚĂŝŶĚĂƚĂŽƌĞǀŝĚĞŶĐĞƚŽƐŚŽǁĐŽŵƉůŝĂŶĐĞĨŽƌƚŚĞ
ĐƵƌƌĞŶƚLJĞĂƌ͕ƉůƵƐƚŚƌĞĞƉƌĞǀŝŽƵƐĐĂůĞŶĚĂƌLJĞĂƌƐƵŶůĞƐƐ͕ĚŝƌĞĐƚĞĚďLJŝƚƐ
ĐŽŵƉůŝĂŶĐĞĞŶĨŽƌĐĞŵĞŶƚĂƵƚŚŽƌŝƚLJ͕ƚŽƌĞƚĂŝŶƐƉĞĐŝĨŝĐĞǀŝĚĞŶĐĞĨŽƌĂůŽŶŐĞƌ
ƉĞƌŝŽĚŽĨƚŝŵĞĂƐƉĂƌƚŽĨĂŶŝŶǀĞƐƚŝŐĂƚŝŽŶ͘ĂƚĂƌĞƋƵŝƌĞĚĨŽƌƚŚĞĐĂůĐƵůĂƚŝŽŶŽĨ
ZĞŐƵůĂƚŝŽŶZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉZĞƉŽƌƚŝŶŐĐĞ͕ŽƌZĞƉŽƌƚŝŶŐ͕W^ϭ͕ĂŶĚ
>ƐŚĂůůďĞƌĞƚĂŝŶĞĚŝŶĚŝŐŝƚĂůĨŽƌŵĂƚĂƚƚŚĞƐĂŵĞƐĐĂŶƌĂƚĞĂƚǁŚŝĐŚƚŚĞ
ZĞƉŽƌƚŝŶŐŝƐĐĂůĐƵůĂƚĞĚĨŽƌƚŚĞĐƵƌƌĞŶƚLJĞĂƌ͕ƉůƵƐƚŚƌĞĞƉƌĞǀŝŽƵƐĐĂůĞŶĚĂƌ
LJĞĂƌƐ͘
/ĨĂZĞƐƉŽŶƐŝďůĞŶƚŝƚLJŝƐĨŽƵŶĚŶŽŶĐŽŵƉůŝĂŶƚ͕ŝƚƐŚĂůůŬĞĞƉŝŶĨŽƌŵĂƚŝŽŶƌĞůĂƚĞĚƚŽ
ƚŚĞŶŽŶĐŽŵƉůŝĂŶĐĞƵŶƚŝůĨŽƵŶĚĐŽŵƉůŝĂŶƚ͕ŽƌĨŽƌƚŚĞƚŝŵĞƉĞƌŝŽĚƐƉĞĐŝĨŝĞĚĂďŽǀĞ͕
ǁŚŝĐŚĞǀĞƌŝƐůŽŶŐĞƌ͘
dŚĞĐŽŵƉůŝĂŶĐĞĞŶĨŽƌĐĞŵĞŶƚĂƵƚŚŽƌŝƚLJƐŚĂůůŬĞĞƉƚŚĞůĂƐƚĂƵĚŝƚƌĞĐŽƌĚƐĂŶĚ
ĂůůƐƵďƐĞƋƵĞŶƚƌĞƋƵĞƐƚĞĚĂŶĚƐƵďŵŝƚƚĞĚƌĞĐŽƌĚƐ͘
ϭ͘ϯ͘ ŽŵƉůŝĂŶĐĞDŽŶŝƚŽƌŝŶŐĂŶĚƐƐĞƐƐŵĞŶƚWƌŽĐĞƐƐĞƐ
ŽŵƉůŝĂŶĐĞƵĚŝƚƐ
^ĞůĨͲĞƌƚŝĨŝĐĂƚŝŽŶƐ
^ƉŽƚŚĞĐŬŝŶŐ
ŽŵƉůŝĂŶĐĞ/ŶǀĞƐƚŝŐĂƚŝŽŶ

>ͲϬϬϭͲϮ
:ƵůLJ͕ϮϬϭϯ



WĂŐĞϲŽĨϭϯ



^ƚĂŶĚĂƌĚ>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
^ĞůĨͲZĞƉŽƌƚŝŶŐ
ŽŵƉůĂŝŶƚƐ
ϭ͘ϰ͘ ĚĚŝƚŝŽŶĂůŽŵƉůŝĂŶĐĞ/ŶĨŽƌŵĂƚŝŽŶ
EŽŶĞ͘
Ϯ͘

sŝŽůĂƚŝŽŶ^ĞǀĞƌŝƚLJ>ĞǀĞůƐ
R
#

Lower VSL

Zϭ dŚĞW^ϭǀĂůƵĞ
ŽĨƚŚĞ
ZĞƐƉŽŶƐŝďůĞ
ŶƚŝƚLJ͕ĨŽƌƚŚĞ
ƉƌĞĐĞĚŝŶŐŽŶĂ
ƌŽůůŝŶŐϭϮ
ĐŽŶƐĞĐƵƚŝǀĞ
ĐĂůĞŶĚĂƌͲ
ŵŽŶƚŚ
ƉĞƌŝŽĚďĂƐŝƐ͕ŝƐ
ůĞƐƐƚŚĂŶϭϬϬ
ƉĞƌĐĞŶƚďƵƚ
ŐƌĞĂƚĞƌƚŚĂŶŽƌ
ĞƋƵĂůƚŽϵϱ
ƉĞƌĐĞŶƚĨŽƌƚŚĞ
ĂƉƉůŝĐĂďůĞ
/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͘
ZϮ dŚĞĂůĂŶĐŝŶŐ
ƵƚŚŽƌŝƚLJ
ĞdžĐĞĞĚĞĚŝƚƐ
ĐůŽĐŬͲŵŝŶƵƚĞ
>ĨŽƌŵŽƌĞ
ƚŚĂŶϯϬ
ĐŽŶƐĞĐƵƚŝǀĞ
ĐůŽĐŬŵŝŶƵƚĞƐ
ďƵƚĨŽƌϰϱ
ĐŽŶƐĞĐƵƚŝǀĞ
ĐůŽĐŬͲŵŝŶƵƚĞƐ
ŽƌůĞƐƐĨŽƌƚŚĞ
ĂƉƉůŝĐĂďůĞ
/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͘

Moderate VSL

High VSL

Severe VSL

dŚĞW^ϭǀĂůƵĞ
ŽĨƚŚĞ
ZĞƐƉŽŶƐŝďůĞ
ŶƚŝƚLJ͕ĨŽƌƚŚĞ
ƉƌĞĐĞĚŝŶŐŽŶĂ
ƌŽůůŝŶŐϭϮ
ĐŽŶƐĞĐƵƚŝǀĞ
ĐĂůĞŶĚĂƌͲ
ŵŽŶƚŚ
ƉĞƌŝŽĚďĂƐŝƐ͕ŝƐ
ůĞƐƐƚŚĂŶϵϱ
ƉĞƌĐĞŶƚ͕ďƵƚ
ŐƌĞĂƚĞƌƚŚĂŶŽƌ
ĞƋƵĂůƚŽϵϬ
ƉĞƌĐĞŶƚĨŽƌƚŚĞ
ĂƉƉůŝĐĂďůĞ
/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͘
dŚĞĂůĂŶĐŝŶŐ
ƵƚŚŽƌŝƚLJ
ĞdžĐĞĞĚĞĚŝƚƐ
ĐůŽĐŬͲŵŝŶƵƚĞ
>ĨŽƌŐƌĞĂƚĞƌ
ƚŚĂŶϰϱ
ĐŽŶƐĞĐƵƚŝǀĞ
ĐůŽĐŬŵŝŶƵƚĞƐ
ďƵƚĨŽƌϲϬ
ĐŽŶƐĞĐƵƚŝǀĞ
ĐůŽĐŬͲŵŝŶƵƚĞƐ
ŽƌůĞƐƐĨŽƌƚŚĞ
ĂƉƉůŝĐĂďůĞ
/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͘

dŚĞW^ϭǀĂůƵĞ
ŽĨƚŚĞ
ZĞƐƉŽŶƐŝďůĞ
ŶƚŝƚLJ͕ĨŽƌƚŚĞ
ƉƌĞĐĞĚŝŶŐŽŶĂ
ƌŽůůŝŶŐϭϮ
ĐŽŶƐĞĐƵƚŝǀĞ
ĐĂůĞŶĚĂƌͲ
ŵŽŶƚŚ
ƉĞƌŝŽĚďĂƐŝƐ͕ŝƐ
ůĞƐƐƚŚĂŶϵϬ
ƉĞƌĐĞŶƚ͕ďƵƚ
ŐƌĞĂƚĞƌƚŚĂŶŽƌ
ĞƋƵĂůƚŽϴϱ
ƉĞƌĐĞŶƚĨŽƌƚŚĞ
ĂƉƉůŝĐĂďůĞ
/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͘
dŚĞĂůĂŶĐŝŶŐ
ƵƚŚŽƌŝƚLJ
ĞdžĐĞĞĚĞĚŝƚƐ
ĐůŽĐŬͲŵŝŶƵƚĞ
>ĨŽƌŐƌĞĂƚĞƌ
ƚŚĂŶϲϬ
ĐŽŶƐĞĐƵƚŝǀĞ
ĐůŽĐŬŵŝŶƵƚĞƐ
ďƵƚĨŽƌϳϱ
ĐŽŶƐĞĐƵƚŝǀĞ
ĐůŽĐŬͲŵŝŶƵƚĞƐ
ŽƌůĞƐƐĨŽƌƚŚĞ
ĂƉƉůŝĐĂďůĞ
/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͘

dŚĞW^ϭǀĂůƵĞŽĨƚŚĞ
ZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͕ĨŽƌ
ƚŚĞƉƌĞĐĞĚŝŶŐŽŶĂ
ƌŽůůŝŶŐϭϮĐŽŶƐĞĐƵƚŝǀĞ
ĐĂůĞŶĚĂƌͲŵŽŶƚŚ
ƉĞƌŝŽĚďĂƐŝƐ͕ŝƐůĞƐƐƚŚĂŶ
ϴϱƉĞƌĐĞŶƚĨŽƌƚŚĞ
ĂƉƉůŝĐĂďůĞ
/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͘

dŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ
ĞdžĐĞĞĚĞĚŝƚƐĐůŽĐŬͲ
ŵŝŶƵƚĞ>ĨŽƌŐƌĞĂƚĞƌ
ƚŚĂŶϳϱĐŽŶƐĞĐƵƚŝǀĞ
ĐůŽĐŬͲŵŝŶƵƚĞƐĨŽƌƚŚĞ
ĂƉƉůŝĐĂďůĞ
/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͘

E. ZĞŐŝŽŶĂůsĂƌŝĂŶĐĞƐ
>ͲϬϬϭͲϮ
:ƵůLJ͕ϮϬϭϯ



WĂŐĞϳŽĨϭϯ



^ƚĂŶĚĂƌĚ>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
EŽŶĞ͘
F. ƐƐŽĐŝĂƚĞĚŽĐƵŵĞŶƚƐ
>ͲϬϬϭͲϮ͕ZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ^ƚĂŶĚĂƌĚĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
sĞƌƐŝŽŶ,ŝƐƚŽƌLJ
sĞƌƐŝŽŶ

ĂƚĞ

ĐƚŝŽŶ

ŚĂŶŐĞdƌĂĐŬŝŶŐ

Ϭ

&ĞďƌƵĂƌLJϴ͕
ϮϬϬϱ

KdƉƉƌŽǀĂů

EĞǁ

Ϭ

Ɖƌŝůϭ͕ϮϬϬϱ

ĨĨĞĐƚŝǀĞ/ŵƉůĞŵĞŶƚĂƚŝŽŶĂƚĞ

EĞǁ

Ϭ

ƵŐƵƐƚϴ͕ϮϬϬϱ

ZĞŵŽǀĞĚ͞WƌŽƉŽƐĞĚ͟ĨƌŽŵĨĨĞĐƚŝǀĞĂƚĞ

ƌƌĂƚĂ

Ϭ

:ƵůLJϮϰ͕ϮϬϬϳ

ŽƌƌĞĐƚĞĚZϯƚŽƌĞĨĞƌĞŶĐĞDϭĂŶĚDϮ
ŝŶƐƚĞĂĚŽĨZϭĂŶĚZϮ

ƌƌĂƚĂ

ϬĂ

ĞĐĞŵďĞƌϭϵ͕
ϮϬϬϳ

ĚĚĞĚƉƉĞŶĚŝdžϮʹ/ŶƚĞƌƉƌĞƚĂƚŝŽŶŽĨZϭ
ĂƉƉƌŽǀĞĚďLJKdŽŶKĐƚŽďĞƌϮϯ͕ϮϬϬϳ

ZĞǀŝƐĞĚ

ϬĂ

:ĂŶƵĂƌLJϭϲ͕
ϮϬϬϴ

/Ŷ^ĞĐƚŝŽŶ͘Ϯ͕͘ĚĚĞĚ͞Ă͟ƚŽĞŶĚŽĨ
ƐƚĂŶĚĂƌĚŶƵŵďĞƌ
/Ŷ^ĞĐƚŝŽŶ&͕ĐŽƌƌĞĐƚĞĚĂƵƚŽŵĂƚŝĐ
ŶƵŵďĞƌŝŶŐĨƌŽŵ͞Ϯ͟ƚŽ͞ϭ͟ĂŶĚƌĞŵŽǀĞĚ
͞ĂƉƉƌŽǀĞĚ͟ĂŶĚĂĚĚĞĚƉĂƌĞŶƚŚĞƐŝƐƚŽ
͞;KĐƚŽďĞƌϮϯ͕ϮϬϬϳͿ͟

ƌƌĂƚĂ

Ϭ

:ĂŶƵĂƌLJϮϯ͕
ϮϬϬϴ

ZĞǀĞƌƐĞĚĞƌƌĂƚĂĐŚĂŶŐĞĨƌŽŵ:ƵůLJϮϰ͕ϮϬϬϳ

ƌƌĂƚĂ

Ϭ͘ϭĂ

KĐƚŽďĞƌϮϵ͕
ϮϬϬϴ

ŽĂƌĚĂƉƉƌŽǀĞĚĞƌƌĂƚĂĐŚĂŶŐĞƐ͖ƵƉĚĂƚĞĚ
ǀĞƌƐŝŽŶŶƵŵďĞƌƚŽ͞Ϭ͘ϭĂ͟

ƌƌĂƚĂ

Ϭ͘ϭĂ

DĂLJϭϯ͕ϮϬϬϵ

ƉƉƌŽǀĞĚďLJ&Z





/ŶĐůƵƐŝŽŶŽĨ>ĂŶĚtsĂƌŝĂŶĐĞĂŶĚ
ĞdžĐůƵƐŝŽŶŽĨW^Ϯ

ZĞǀŝƐŝŽŶ

ϭ

>ͲϬϬϭͲϮ
:ƵůLJ͕ϮϬϭϯ



WĂŐĞϴŽĨϭϯ



^ƚĂŶĚĂƌĚ>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
ƚƚĂĐŚŵĞŶƚϭ
ƋƵĂƚŝŽŶƐ^ƵƉƉŽƌƚŝŶŐZĞƋƵŝƌĞŵĞŶƚZϭĂŶĚDĞĂƐƵƌĞDϭ

W^ϭŝƐĐĂůĐƵůĂƚĞĚĂƐĨŽůůŽǁƐ͗

W^ϭс;ϮͲ&ͿΎϭϬϬй

dŚĞĨƌĞƋƵĞŶĐLJͲƌĞůĂƚĞĚĐŽŵƉůŝĂŶĐĞĨĂĐƚŽƌ;&Ϳ͕ŝƐĂƌĂƚŝŽŽĨƚŚĞĂĐĐƵŵƵůĂƚŝŶŐĐůŽĐŬͲŵŝŶƵƚĞ
ĐŽŵƉůŝĂŶĐĞƉĂƌĂŵĞƚĞƌƐĨŽƌƚŚĞŵŽƐƚƌĞĐĞŶƚƉƌĞĐĞĚŝŶŐĐŽŶƐĞĐƵƚŝǀĞϭϮĐŽŶƐĞĐƵƚŝǀĞͲ
ĐĂůĞŶĚĂƌŵŽŶƚŚƐ͕ĚŝǀŝĚĞĚďLJƚŚĞƐƋƵĂƌĞŽĨƚŚĞƚĂƌŐĞƚĨƌĞƋƵĞŶĐLJďŽƵŶĚ͗
& с

& ϭϮͲ ŵŽŶƚŚ
;ɸϭ/ͿϮ

tŚĞƌĞɸϭ/ŝƐƚŚĞĐŽŶƐƚĂŶƚĚĞƌŝǀĞĚĨƌŽŵĂƚĂƌŐĞƚĞĚĨƌĞƋƵĞŶĐLJďŽƵŶĚĨŽƌĞĂĐŚ
/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶĂƐĨŽůůŽǁƐ͗
•

ĂƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶɸϭ/сϬ͘Ϭϭϴ,nj

•

tĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶɸϭ/сϬ͘ϬϮϮϴ,nj

•

ZKd/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶɸϭ/сϬ͘ϬϯϬ,nj

•

YƵĞďĞĐ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶɸϭ/сϬ͘ϬϮϭ,nj

dŚĞƌĂƚŝŶŐŝŶĚĞdž&ϭϮͲŵŽŶƚŚŝƐĚĞƌŝǀĞĚĨƌŽŵƚŚĞŵŽƐƚƌĞĐĞŶƚƉƌĞĐĞĚŝŶŐĐŽŶƐĞĐƵƚŝǀĞϭϮ
ĐŽŶƐĞĐƵƚŝǀĞͲĐĂůĞŶĚĂƌŵŽŶƚŚƐŽĨĚĂƚĂ͘dŚĞĂĐĐƵŵƵůĂƚŝŶŐĐůŽĐŬͲŵŝŶƵƚĞĐŽŵƉůŝĂŶĐĞ
ƉĂƌĂŵĞƚĞƌƐĂƌĞĚĞƌŝǀĞĚĨƌŽŵƚŚĞŽŶĞͲŵŝŶƵƚĞĂǀĞƌĂŐĞƐŽĨZĞƉŽƌƚŝŶŐ͕&ƌĞƋƵĞŶĐLJƌƌŽƌ͕
ĂŶĚ&ƌĞƋƵĞŶĐLJŝĂƐ^ĞƚƚŝŶŐƐ͘
ĐůŽĐŬͲŵŝŶƵƚĞĂǀĞƌĂŐĞŝƐƚŚĞĂǀĞƌĂŐĞŽĨƚŚĞƌĞƉŽƌƚŝŶŐĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛ƐǀĂůŝĚ
ŵĞĂƐƵƌĞĚǀĂƌŝĂďůĞ;ŝ͘Ğ͕͘ĨŽƌZĞƉŽƌƚŝŶŐ;ZͿĂŶĚĨŽƌ&ƌĞƋƵĞŶĐLJƌƌŽƌͿĨŽƌĞĂĐŚ
ƐĂŵƉůŝŶŐĐLJĐůĞĚƵƌŝŶŐĂŐŝǀĞŶĐůŽĐŬͲŵŝŶƵƚĞ͘

§ RACE·
¨
¸
© − 10 B ¹clock -minute

§ ¦ RACE
sampling cycles in clock - minute
¨
¨
nsampling cycles in clock -minute
=©
- 10B

·
¸
¸
¹

ŶĚ͕

¦ ΔF

ΔFclock -minute =

sampling cycles in clock - minute

nsampling cycles in clock -minute

dŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛ƐĐůŽĐŬͲŵŝŶƵƚĞĐŽŵƉůŝĂŶĐĞĨĂĐƚŽƌ;&ĐůŽĐŬͲŵŝŶƵƚĞͿĐĂůĐƵůĂƚŝŽŶŝƐ͗

>ͲϬϬϭͲϮ
:ƵůLJ͕ϮϬϭϯ



WĂŐĞϵŽĨϭϯ



^ƚĂŶĚĂƌĚ>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
ª§ RACE·
º
* ΔFclock -minute »
CFclock -minute = Ǭ
¸
¬© − 10 B ¹ clock -minute
¼
EŽƌŵĂůůLJ͕ϲϬĐůŽĐŬͲŵŝŶƵƚĞĂǀĞƌĂŐĞƐŽĨƚŚĞƌĞƉŽƌƚŝŶŐĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛ƐZĞƉŽƌƚŝŶŐ
ĂŶĚ&ƌĞƋƵĞŶĐLJƌƌŽƌǁŝůůďĞƵƐĞĚƚŽĐŽŵƉƵƚĞƚŚĞŚŽƵƌůLJĂǀĞƌĂŐĞĐŽŵƉůŝĂŶĐĞĨĂĐƚŽƌ;&ĐůŽĐŬͲ
ŚŽƵƌͿ͘

CFclock -hour =

¦ CF

clock - minute

nclock -minute samples in hour

dŚĞƌĞƉŽƌƚŝŶŐĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJƐŚĂůůďĞĂďůĞƚŽƌĞĐĂůĐƵůĂƚĞĂŶĚƐƚŽƌĞĞĂĐŚŽĨƚŚĞ
ƌĞƐƉĞĐƚŝǀĞĐůŽĐŬͲŚŽƵƌĂǀĞƌĂŐĞƐ;&ĐůŽĐŬͲŚŽƵƌĂǀĞƌĂŐĞͲŵŽŶƚŚͿĂŶĚƚŚĞĚĂƚĂƐĂŵƉůĞƐĨŽƌĞĂĐŚϮϰͲ
ŚŽƵƌƉĞƌŝŽĚ;ŽŶĞĨŽƌĞĂĐŚĐůŽĐŬͲŚŽƵƌ͖ŝ͘Ğ͕͘ŚŽƵƌĞŶĚŝŶŐ;,ͿϬϭϬϬ͕,ϬϮϬϬ͕͕͘͘͘,ϮϰϬϬͿ͘
dŽĐĂůĐƵůĂƚĞƚŚĞŵŽŶƚŚůLJĐŽŵƉůŝĂŶĐĞĨĂĐƚŽƌ;&ŵŽŶƚŚͿ͗

¦ [(CF
¦ [n

clock - hour

CFclock -hour average - month =

)( none -minute samples in clock - hour )]

days -in - month

one - minute samples in clock - hour
days - in month

¦ [(CF

clock - hour average - month

CFmonth =

hours - in - day

¦ [n

]

)( none - minute samples in clock - hour averages )]

one - minute samples in clock - hour averages

]

hours - in day

dŽĐĂůĐƵůĂƚĞƚŚĞϭϮͲŵŽŶƚŚĐŽŵƉůŝĂŶĐĞĨĂĐƚŽƌ;&ϭϮŵŽŶƚŚͿ͗
12

¦ (CF

month -i

CF12-month =

i =1

)(n(one -minute samples in month )−i )]

12

¦ [n

( one -minute samples in month) -i

]

i =1

dŽĞŶƐƵƌĞƚŚĂƚƚŚĞĂǀĞƌĂŐĞZĞƉŽƌƚŝŶŐĂŶĚ&ƌĞƋƵĞŶĐLJƌƌŽƌĐĂůĐƵůĂƚĞĚĨŽƌĂŶLJŽŶĞͲ
ŵŝŶƵƚĞŝŶƚĞƌǀĂůŝƐƌĞƉƌĞƐĞŶƚĂƚŝǀĞŽĨƚŚĂƚƚŝŵĞŝŶƚĞƌǀĂů͕ŝƚŝƐŶĞĐĞƐƐĂƌLJƚŚĂƚĂƚůĞĂƐƚϱϬ
ƉĞƌĐĞŶƚŽĨďŽƚŚƚŚĞZĞƉŽƌƚŝŶŐĂŶĚ&ƌĞƋƵĞŶĐLJƌƌŽƌƐĂŵƉůĞĚĂƚĂĚƵƌŝŶŐƚŚĞŽŶĞͲ
ŵŝŶƵƚĞŝŶƚĞƌǀĂůŝƐǀĂůŝĚ͘/ĨƚŚĞƌĞĐŽƌĚŝŶŐŽĨZĞƉŽƌƚŝŶŐŽƌ&ƌĞƋƵĞŶĐLJƌƌŽƌŝƐŝŶƚĞƌƌƵƉƚĞĚ
ƐƵĐŚƚŚĂƚůĞƐƐƚŚĂŶϱϬƉĞƌĐĞŶƚŽĨƚŚĞŽŶĞͲŵŝŶƵƚĞƐĂŵƉůĞƉĞƌŝŽĚĚĂƚĂŝƐĂǀĂŝůĂďůĞŽƌǀĂůŝĚ͕
ƚŚĞŶƚŚĂƚŽŶĞͲŵŝŶƵƚĞŝŶƚĞƌǀĂůŝƐĞdžĐůƵĚĞĚĨƌŽŵƚŚĞW^ϭĐĂůĐƵůĂƚŝŽŶ͘

ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJƉƌŽǀŝĚŝŶŐKǀĞƌůĂƉZĞŐƵůĂƚŝŽŶ^ĞƌǀŝĐĞƚŽĂŶŽƚŚĞƌĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ
ĐĂůĐƵůĂƚĞƐŝƚƐW^ϭƉĞƌĨŽƌŵĂŶĐĞĂĨƚĞƌĐŽŵďŝŶŝŶŐŝƚƐZĞƉŽƌƚŝŶŐĂŶĚ&ƌĞƋƵĞŶĐLJŝĂƐ
>ͲϬϬϭͲϮ
:ƵůLJ͕ϮϬϭϯ



WĂŐĞϭϬŽĨϭϯ



^ƚĂŶĚĂƌĚ>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
^ĞƚƚŝŶŐƐǁŝƚŚƚŚĞZĞƉŽƌƚŝŶŐĂŶĚ&ƌĞƋƵĞŶĐLJŝĂƐ^ĞƚƚŝŶŐƐŽĨƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ
ƌĞĐĞŝǀŝŶŐƚŚĞZĞŐƵůĂƚŝŽŶ^ĞƌǀŝĐĞ͘



>ͲϬϬϭͲϮ
:ƵůLJ͕ϮϬϭϯ



WĂŐĞϭϭŽĨϭϯ



^ƚĂŶĚĂƌĚ>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
ƚƚĂĐŚŵĞŶƚϮ

ƋƵĂƚŝŽŶƐ^ƵƉƉŽƌƚŝŶŐZĞƋƵŝƌĞŵĞŶƚZϮĂŶĚDĞĂƐƵƌĞDϮ


tŚĞŶĂĐƚƵĂůĨƌĞƋƵĞŶĐLJŝƐĞƋƵĂůƚŽ^ĐŚĞĚƵůĞĚ&ƌĞƋƵĞŶĐLJ͕>,ŝŐŚĂŶĚ>>ŽǁĚŽŶŽƚĂƉƉůLJ͘
tŚĞŶĂĐƚƵĂůĨƌĞƋƵĞŶĐLJŝƐůĞƐƐƚŚĂŶ^ĐŚĞĚƵůĞĚ&ƌĞƋƵĞŶĐLJ͕>,ŝŐŚĚŽĞƐŶŽƚĂƉƉůLJ͕ĂŶĚ
>>ŽǁŝƐĐĂůĐƵůĂƚĞĚĂƐ͗
BAAL Low = (− 10 Bi × (FTL Low − FS ))×

(FTL Low − FS )
(FA − FS )

tŚĞŶĂĐƚƵĂůĨƌĞƋƵĞŶĐLJŝƐŐƌĞĂƚĞƌƚŚĂŶ^ĐŚĞĚƵůĞĚ&ƌĞƋƵĞŶĐLJ͕>>ŽǁĚŽĞƐŶŽƚĂƉƉůLJĂŶĚ
ƚŚĞ>,ŝŐŚŝƐĐĂůĐƵůĂƚĞĚĂƐ͗
BAALHigh = (− 10 Bi × (FTLHigh − FS ))×

(FTL

High

− FS )

(FA − FS )

tŚĞƌĞ͗
>>ŽǁŝƐƚŚĞ>ŽǁĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ>ŝŵŝƚ;DtͿ
>,ŝŐŚŝƐƚŚĞ,ŝŐŚĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ>ŝŵŝƚ;DtͿ
ϭϬŝƐĂĐŽŶƐƚĂŶƚƚŽĐŽŶǀĞƌƚƚŚĞ&ƌĞƋƵĞŶĐLJŝĂƐ^ĞƚƚŝŶŐĨƌŽŵDtͬϬ͘ϭ,njƚŽDtͬ,nj
ŝŝƐƚŚĞ&ƌĞƋƵĞŶĐLJŝĂƐ^ĞƚƚŝŶŐĨŽƌĂĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ;ĞdžƉƌĞƐƐĞĚĂƐDtͬϬ͘ϭ,njͿ
&ŝƐƚŚĞŵĞĂƐƵƌĞĚĨƌĞƋƵĞŶĐLJŝŶ,nj͘
&^ŝƐƚŚĞƐĐŚĞĚƵůĞĚĨƌĞƋƵĞŶĐLJŝŶ,nj͘
&d>>ŽǁŝƐƚŚĞ>Žǁ&ƌĞƋƵĞŶĐLJdƌŝŐŐĞƌ>ŝŵŝƚ;ĐĂůĐƵůĂƚĞĚĂƐ&^Ͳϯɸϭ/,njͿ
&d>,ŝŐŚŝƐƚŚĞ,ŝŐŚ&ƌĞƋƵĞŶĐLJdƌŝŐŐĞƌ>ŝŵŝƚ;ĐĂůĐƵůĂƚĞĚĂƐ&^нϯɸϭ/,njͿ
tŚĞƌĞɸϭ/ŝƐƚŚĞĐŽŶƐƚĂŶƚĚĞƌŝǀĞĚĨƌŽŵĂƚĂƌŐĞƚĞĚĨƌĞƋƵĞŶĐLJďŽƵŶĚĨŽƌĞĂĐŚ
/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶĂƐĨŽůůŽǁƐ͗
•

ĂƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶɸϭ/сϬ͘Ϭϭϴ,nj

•

tĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶɸϭ/сϬ͘ϬϮϮϴ,nj

•

ZKd/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶɸϭ/сϬ͘ϬϯϬ,nj

•

YƵĞďĞĐ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶɸϭ/сϬ͘ϬϮϭ,nj


dŽĞŶƐƵƌĞƚŚĂƚƚŚĞĂǀĞƌĂŐĞĂĐƚƵĂůĨƌĞƋƵĞŶĐLJĐĂůĐƵůĂƚĞĚĨŽƌĂŶLJŽŶĞͲŵŝŶƵƚĞŝŶƚĞƌǀĂůŝƐ
ƌĞƉƌĞƐĞŶƚĂƚŝǀĞŽĨƚŚĂƚƚŝŵĞŝŶƚĞƌǀĂů͕ŝƚŝƐŶĞĐĞƐƐĂƌLJƚŚĂƚĂƚůĞĂƐƚϱϬйŽĨƚŚĞĂĐƚƵĂů
ĨƌĞƋƵĞŶĐLJƐĂŵƉůĞĚĂƚĂĚƵƌŝŶŐƚŚĂƚŽŶĞͲŵŝŶƵƚĞŝŶƚĞƌǀĂůŝƐǀĂůŝĚ͘/ĨƚŚĞƌĞĐŽƌĚŝŶŐŽĨĂĐƚƵĂů
ĨƌĞƋƵĞŶĐLJŝƐŝŶƚĞƌƌƵƉƚĞĚƐƵĐŚƚŚĂƚůĞƐƐƚŚĂŶϱϬƉĞƌĐĞŶƚŽĨƚŚĞŽŶĞͲŵŝŶƵƚĞƐĂŵƉůĞƉĞƌŝŽĚ
>ͲϬϬϭͲϮ
:ƵůLJ͕ϮϬϭϯ



WĂŐĞϭϮŽĨϭϯ



^ƚĂŶĚĂƌĚ>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
ĚĂƚĂŝƐĂǀĂŝůĂďůĞŽƌǀĂůŝĚ͕ƚŚĞŶƚŚĂƚŽŶĞͲŵŝŶƵƚĞŝŶƚĞƌǀĂůŝƐĞdžĐůƵĚĞĚĨƌŽŵƚŚĞ>
ĐĂůĐƵůĂƚŝŽŶĂŶĚƚŚĞϯϬͲŵŝŶƵƚĞĐůŽĐŬǁŽƵůĚďĞƌĞƐĞƚƚŽnjĞƌŽ͘

ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJƉƌŽǀŝĚŝŶŐKǀĞƌůĂƉZĞŐƵůĂƚŝŽŶ^ĞƌǀŝĐĞƚŽĂŶŽƚŚĞƌĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ
ĐĂůĐƵůĂƚĞƐŝƚƐ>ƉĞƌĨŽƌŵĂŶĐĞĂĨƚĞƌĐŽŵďŝŶŝŶŐŝƚƐ&ƌĞƋƵĞŶĐLJŝĂƐ^ĞƚƚŝŶŐǁŝƚŚƚŚĞ
&ƌĞƋƵĞŶĐLJŝĂƐ^ĞƚƚŝŶŐŽĨƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJƌĞĐĞŝǀŝŶŐKǀĞƌůĂƉZĞŐƵůĂƚŝŽŶ^ĞƌǀŝĐĞ͘


>ͲϬϬϭͲϮ
:ƵůLJ͕ϮϬϭϯ



WĂŐĞϭϯŽĨϭϯ



,PSOHPHQWDWLRQ3ODQ
3URMHFW%DODQFLQJ$XWKRULW\5HOLDELOLW\EDVHG&RQWUROV
5HVHUYHV



/ŵƉůĞŵĞŶƚĂƚŝŽŶWůĂŶĨŽƌ>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ

ƉƉƌŽǀĂůƐZĞƋƵŝƌĞĚ
>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ

WƌĞƌĞƋƵŝƐŝƚĞƉƉƌŽǀĂůƐ
EŽŶĞ

ZĞǀŝƐŝŽŶƐƚŽ'ůŽƐƐĂƌLJdĞƌŵƐ
dŚĞĨŽůůŽǁŝŶŐĚĞĨŝŶŝƚŝŽŶƐƐŚĂůůďĞĐŽŵĞĞĨĨĞĐƚŝǀĞǁŚĞŶ>ͲϬϬϭͲϮďĞĐŽŵĞƐĞĨĨĞĐƚŝǀĞ͗

ZĞŐƵůĂƚŝŽŶZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ͗ŐƌŽƵƉǁŚŽƐĞŵĞŵďĞƌƐĐŽŶƐŝƐƚŽĨƚǁŽŽƌŵŽƌĞĂůĂŶĐŝŶŐ
ƵƚŚŽƌŝƚŝĞƐƚŚĂƚĐŽůůĞĐƚŝǀĞůLJŵĂŝŶƚĂŝŶ͕ĂůůŽĐĂƚĞ͕ĂŶĚƐƵƉƉůLJƚŚĞZĞŐƵůĂƚŝŶŐZƌĞƐĞƌǀĞƌĞƋƵŝƌĞĚĨŽƌ
ĂůůŵĞŵďĞƌĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐƚŽƵƐĞŝŶŵĞĞƚŝŶŐĂƉƉůŝĐĂďůĞƌĞŐƵůĂƚŝŶŐƐƚĂŶĚĂƌĚƐ͘

ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉZĞƉŽƌƚŝŶŐ͗ƚĂŶLJŐŝǀĞŶƚŝŵĞŽĨŵĞĂƐƵƌĞŵĞŶƚĨŽƌƚŚĞĂƉƉůŝĐĂďůĞ
ZĞŐƵůĂƚŝŽŶZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ͕ƚŚĞĂůŐĞďƌĂŝĐƐƵŵŽĨƚŚĞZĞƉŽƌƚŝŶŐƐ;ŽƌĞƋƵŝǀĂůĞŶƚĂƐ
ĐĂůĐƵůĂƚĞĚĂƚƐƵĐŚƚŝŵĞŽĨŵĞĂƐƵƌĞŵĞŶƚͿŽĨƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐƉĂƌƚŝĐŝƉĂƚŝŶŐŝŶƚŚĞ
ZĞŐƵůĂƚŝŽŶZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉĂƚƚŚĞƚŝŵĞŽĨŵĞĂƐƵƌĞŵĞŶƚ͘

ZĞƉŽƌƚŝŶŐ͗dŚĞƐĐĂŶƌĂƚĞǀĂůƵĞƐŽĨĂĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛ƐƌĞĂŽŶƚƌŽůƌƌŽƌ;Ϳ
ŵĞĂƐƵƌĞĚŝŶDt͕ǁŚŝĐŚŝŶĐůƵĚĞƐƚŚĞĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛ƐEĞƚĐƚƵĂů
/ŶƚĞƌĐŚĂŶŐĞĂŶĚŝƚƐEĞƚ^ĐŚĞĚƵůĞĚ/ŶƚĞƌĐŚĂŶŐĞ͕ƉůƵƐŝƚƐ&ƌĞƋƵĞŶĐLJŝĂƐŽďůŝŐĂƚŝŽŶ͕ƉůƵƐĂŶLJ
ŬŶŽǁŶŵĞƚĞƌĞƌƌŽƌ͘/ŶƚŚĞtĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͕ZĞƉŽƌƚŝŶŐŝŶĐůƵĚĞƐƵƚŽŵĂƚŝĐdŝŵĞ
ƌƌŽƌŽƌƌĞĐƚŝŽŶ;dͿ͘
ZĞƉŽƌƚŝŶŐŝƐĐĂůĐƵůĂƚĞĚĂƐĨŽůůŽǁƐ͗

ZĞƉŽƌƚŝŶŐс;E/оE/^ͿоϭϬ;&о&^Ϳо/D

ZĞƉŽƌƚŝŶŐŝƐĐĂůĐƵůĂƚĞĚŝŶƚŚĞtĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶĂƐĨŽůůŽǁƐ͗

ZĞƉŽƌƚŝŶŐс;E/оE/^ͿоϭϬ;&о&^Ϳо/Dн/d


tŚĞƌĞ͗
E/;ĐƚƵĂůEĞƚ/ŶƚĞƌĐŚĂŶŐĞͿŝƐƚŚĞĂůŐĞďƌĂŝĐƐƵŵŽĨĂĐƚƵĂůŵĞŐĂǁĂƚƚƚƌĂŶƐĨĞƌƐĂĐƌŽƐƐĂůů
dŝĞ>ŝŶĞƐĂŶĚŝŶĐůƵĚĞƐWƐĞƵĚŽͲdŝĞƐ͘ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐĚŝƌĞĐƚůLJĐŽŶŶĞĐƚĞĚǀŝĂ
ĂƐLJŶĐŚƌŽŶŽƵƐƚŝĞƐƚŽĂŶŽƚŚĞƌ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶŵĂLJŝŶĐůƵĚĞŽƌĞdžĐůƵĚĞŵĞŐĂǁĂƚƚ
ƚƌĂŶƐĨĞƌƐŽŶƚŚŽƐĞdŝĞ>ŝŶĞƐŝŶƚŚĞŝƌĂĐƚƵĂůŝŶƚĞƌĐŚĂŶŐĞ͕ƉƌŽǀŝĚĞĚƚŚĞLJĂƌĞŝŵƉůĞŵĞŶƚĞĚ
ŝŶƚŚĞƐĂŵĞŵĂŶŶĞƌĨŽƌEĞƚ/ŶƚĞƌĐŚĂŶŐĞ^ĐŚĞĚƵůĞ͘
E/^;^ĐŚĞĚƵůĞĚEĞƚ/ŶƚĞƌĐŚĂŶŐĞͿŝƐƚŚĞĂůŐĞďƌĂŝĐƐƵŵŽĨĂůůƐĐŚĞĚƵůĞĚŵĞŐĂǁĂƚƚ
ƚƌĂŶƐĨĞƌƐ͕ŝŶĐůƵĚŝŶŐLJŶĂŵŝĐ^ĐŚĞĚƵůĞƐ͕ǁŝƚŚĂĚũĂĐĞŶƚĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐ͕ĂŶĚƚĂŬŝŶŐ
ŝŶƚŽĂĐĐŽƵŶƚƚŚĞĞĨĨĞĐƚƐŽĨƐĐŚĞĚƵůĞƌĂŵƉƐ͘ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐĚŝƌĞĐƚůLJĐŽŶŶĞĐƚĞĚǀŝĂ
ĂƐLJŶĐŚƌŽŶŽƵƐƚŝĞƐƚŽĂŶŽƚŚĞƌ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶŵĂLJŝŶĐůƵĚĞŽƌĞdžĐůƵĚĞŵĞŐĂǁĂƚƚ
ƚƌĂŶƐĨĞƌƐŽŶƚŚŽƐĞdŝĞ>ŝŶĞƐŝŶƚŚĞŝƌƐĐŚĞĚƵůĞĚ/ŶƚĞƌĐŚĂŶŐĞ͕ƉƌŽǀŝĚĞĚƚŚĞLJĂƌĞ
ŝŵƉůĞŵĞŶƚĞĚŝŶƚŚĞƐĂŵĞŵĂŶŶĞƌĨŽƌEĞƚ/ŶƚĞƌĐŚĂŶŐĞĐƚƵĂů͘
;&ƌĞƋƵĞŶĐLJŝĂƐ^ĞƚƚŝŶŐͿŝƐƚŚĞ&ƌĞƋƵĞŶĐLJŝĂƐ^ĞƚƚŝŶŐ;ŝŶŶĞŐĂƚŝǀĞDtͬϬ͘ϭ,njͿĨŽƌƚŚĞ
ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͘
ϭϬŝƐƚŚĞĐŽŶƐƚĂŶƚĨĂĐƚŽƌƚŚĂƚĐŽŶǀĞƌƚƐƚŚĞĨƌĞƋƵĞŶĐLJďŝĂƐƐĞƚƚŝŶŐƵŶŝƚƐƚŽDtͬ,nj͘
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&^;^ĐŚĞĚƵůĞĚ&ƌĞƋƵĞŶĐLJͿŝƐϲϬ͘Ϭ,nj͕ĞdžĐĞƉƚĚƵƌŝŶŐĂƚŝŵĞĐŽƌƌĞĐƚŝŽŶ͘
/D;/ŶƚĞƌĐŚĂŶŐĞDĞƚĞƌƌƌŽƌͿŝƐƚŚĞŵĞƚĞƌĞƌƌŽƌĐŽƌƌĞĐƚŝŽŶĨĂĐƚŽƌĂŶĚƌĞƉƌĞƐĞŶƚƐƚŚĞ
ĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶƚŚĞŝŶƚĞŐƌĂƚĞĚŚŽƵƌůLJĂǀĞƌĂŐĞŽĨƚŚĞŶĞƚŝŶƚĞƌĐŚĂŶŐĞĂĐƚƵĂů;E/Ϳ
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/d;ƵƚŽŵĂƚŝĐdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶͿŝƐƚŚĞĂĚĚŝƚŝŽŶŽĨĂĐŽŵƉŽŶĞŶƚƚŽƚŚĞ
ĞƋƵĂƚŝŽŶĨŽƌƚŚĞtĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶƚŚĂƚŵŽĚŝĨŝĞƐƚŚĞĐŽŶƚƌŽůƉŽŝŶƚĨŽƌƚŚĞ
ƉƵƌƉŽƐĞŽĨĐŽŶƚŝŶƵŽƵƐůLJƉĂLJŝŶŐďĂĐŬWƌŝŵĂƌLJ/ŶĂĚǀĞƌƚĞŶƚ/ŶƚĞƌĐŚĂŶŐĞƚŽĐŽƌƌĞĐƚ
ĂĐĐƵŵƵůĂƚĞĚƚŝŵĞĞƌƌŽƌ͘ƵƚŽŵĂƚŝĐdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶŝƐŽŶůLJĂƉƉůŝĐĂďůĞŝŶƚŚĞ
tĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͘
on/off peak

IATEC

= PII

accum

(1 − Y )* H

ǁŚĞŶŽƉĞƌĂƚŝŶŐŝŶƵƚŽŵĂƚŝĐdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶĐŽŶƚƌŽůŵŽĚĞ͘

/dƐŚĂůůďĞnjĞƌŽǁŚĞŶŽƉĞƌĂƚŝŶŐŝŶĂŶLJŽƚŚĞƌ'ŵŽĚĞ͘
•

zсͬ^͘

•

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ǀĂůƵĞŽĨ,ŝƐƐĞƚƚŽϯ͘

•

^с&ƌĞƋƵĞŶĐLJŝĂƐĨŽƌƚŚĞ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ;DtͬϬ͘ϭ,njͿ͘

•

WƌŝŵĂƌLJ/ŶĂĚǀĞƌƚĞŶƚ/ŶƚĞƌĐŚĂŶŐĞ;W//ŚŽƵƌůLJͿŝƐ;ϭͲzͿΎ;//ĂĐƚƵĂůͲΎȴdͬϲͿ

•

//ĂĐƚƵĂůŝƐƚŚĞŚŽƵƌůLJ/ŶĂĚǀĞƌƚĞŶƚ/ŶƚĞƌĐŚĂŶŐĞĨŽƌƚŚĞůĂƐƚŚŽƵƌ͘

>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
:ƵůLJ͕ϮϬϭϯ

Ϯ

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ȴdŝƐƚŚĞŚŽƵƌůLJĐŚĂŶŐĞŝŶƐLJƐƚĞŵdŝŵĞƌƌŽƌĂƐĚŝƐƚƌŝďƵƚĞĚďLJƚŚĞ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ
dŝŵĞDŽŶŝƚŽƌ͘tŚĞƌĞ͗



ȴdсdĞŶĚŚŽƵƌʹdďĞŐŝŶŚŽƵƌʹdĂĚũʹ;ƚͿΎ;dŽĨĨƐĞƚͿ

•

dĂĚũŝƐƚŚĞZĞůŝĂďŝůŝƚLJŽŽƌĚŝŶĂƚŽƌĂĚũƵƐƚŵĞŶƚĨŽƌĚŝĨĨĞƌĞŶĐĞƐǁŝƚŚ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ
dŝŵĞDŽŶŝƚŽƌĐŽŶƚƌŽůĐĞŶƚĞƌĐůŽĐŬƐ͘

•

ƚŝƐƚŚĞŶƵŵďĞƌŽĨŵŝŶƵƚĞƐŽĨDĂŶƵĂůdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶƚŚĂƚŽĐĐƵƌƌĞĚĚƵƌŝŶŐƚŚĞ
ŚŽƵƌ͘

•

dŽĨĨƐĞƚŝƐϬ͘ϬϬϬŽƌнϬ͘ϬϮϬŽƌͲϬ͘ϬϮϬ͘

•

W//ĂĐĐƵŵŝƐƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛ƐĂĐĐƵŵƵůĂƚĞĚW//ŚŽƵƌůLJŝŶDtŚ͘ŶKŶͲWĞĂŬĂŶĚ
KĨĨͲWĞĂŬĂĐĐƵŵƵůĂƚŝŽŶĂĐĐŽƵŶƚŝŶŐŝƐƌĞƋƵŝƌĞĚ͘
tŚĞƌĞ͗

PII

on/off peak
accum

сůĂƐƚƉĞƌŝŽĚ͛Ɛ

on/off peak

PII

accum

нW//ŚŽƵƌůLJ



ůůEZ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶƐǁŝƚŚŵƵůƚŝƉůĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐŽƉĞƌĂƚĞƵƐŝŶŐƚŚĞƉƌŝŶĐŝƉůĞƐ
ŽĨdŝĞͲůŝŶĞŝĂƐ;d>ͿŽŶƚƌŽůĂŶĚƌĞƋƵŝƌĞƚŚĞƵƐĞŽĨĂŶĞƋƵĂƚŝŽŶƐŝŵŝůĂƌƚŽƚŚĞZĞƉŽƌƚŝŶŐ
ĚĞĨŝŶĞĚĂďŽǀĞ͘ŶLJŵŽĚŝĨŝĐĂƚŝŽŶ;ƐͿƚŽƚŚŝƐƐƉĞĐŝĨŝĞĚZĞƉŽƌƚŝŶŐĞƋƵĂƚŝŽŶƚŚĂƚ
ŝƐ;ĂƌĞͿŝŵƉůĞŵĞŶƚĞĚĨŽƌĂůůƐŽŶĂŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶĂŶĚŝƐ;ĂƌĞͿĐŽŶƐŝƐƚĞŶƚǁŝƚŚƚŚĞ
ĨŽůůŽǁŝŶŐĨŽƵƌƉƌŝŶĐŝƉůĞƐǁŝůůƉƌŽǀŝĚĞĂǀĂůŝĚĂůƚĞƌŶĂƚŝǀĞZĞƉŽƌƚŝŶŐĞƋƵĂƚŝŽŶĐŽŶƐŝƐƚĞŶƚ
ǁŝƚŚƚŚĞŵĞĂƐƵƌĞƐŝŶĐůƵĚĞĚŝŶƚŚŝƐƐƚĂŶĚĂƌĚ͘
ϭ͘ ůůƉŽƌƚŝŽŶƐŽĨƚŚĞ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶĂƌĞŝŶĐůƵĚĞĚŝŶŽŶĞĂƌĞĂŽƌĂŶŽƚŚĞƌƐŽƚŚĂƚƚŚĞ
ƐƵŵŽĨĂůůĂƌĞĂŐĞŶĞƌĂƚŝŽŶ͕ůŽĂĚƐĂŶĚůŽƐƐĞƐŝƐƚŚĞƐĂŵĞĂƐƚŽƚĂůƐLJƐƚĞŵŐĞŶĞƌĂƚŝŽŶ͕
ůŽĂĚĂŶĚůŽƐƐĞƐ͘
Ϯ͘ dŚĞĂůŐĞďƌĂŝĐƐƵŵŽĨĂůůĂƌĞĂEĞƚ/ŶƚĞƌĐŚĂŶŐĞ^ĐŚĞĚƵůĞƐĂŶĚĂůůEĞƚ/ŶƚĞƌĐŚĂŶŐĞ
ĂĐƚƵĂůǀĂůƵĞƐŝƐĞƋƵĂůƚŽnjĞƌŽĂƚĂůůƚŝŵĞƐ͘
ϯ͘ dŚĞƵƐĞŽĨĂĐŽŵŵŽŶ^ĐŚĞĚƵůĞĚ&ƌĞƋƵĞŶĐLJ&^ĨŽƌĂůůĂƌĞĂƐĂƚĂůůƚŝŵĞƐ͘
ϰ͘ dŚĞĂďƐĞŶĐĞŽĨŵĞƚĞƌŝŶŐŽƌĐŽŵƉƵƚĂƚŝŽŶĂůĞƌƌŽƌƐ͘;dŚĞŝŶĐůƵƐŝŽŶĂŶĚƵƐĞŽĨƚŚĞ/D
ƚĞƌŵƚŽĂĐĐŽƵŶƚĨŽƌŬŶŽǁŶŵĞƚĞƌŝŶŐŽƌĐŽŵƉƵƚĂƚŝŽŶĂůĞƌƌŽƌƐ͘Ϳ
/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͗tŚĞŶĐĂƉŝƚĂůŝnjĞĚ͕ĂŶLJŽŶĞŽĨƚŚĞĨŽƵƌŵĂũŽƌĞůĞĐƚƌŝĐƐLJƐƚĞŵŶĞƚǁŽƌŬƐŝŶEŽƌƚŚ
ŵĞƌŝĐĂ͗ĂƐƚĞƌŶ͕tĞƐƚĞƌŶ͕ZKdĂŶĚYƵĞďĞĐ͘

dŚĞĞdžŝƐƚŝŶŐĚĞĨŝŶŝƚŝŽŶŽĨ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶƐŚŽƵůĚďĞƌĞƚŝƌĞĚĂƚŵŝĚŶŝŐŚƚŽĨƚŚĞĚĂLJŝŵŵĞĚŝĂƚĞůLJƉƌŝŽƌƚŽ
ƚŚĞĞĨĨĞĐƚŝǀĞĚĂƚĞŽĨ>ͲϬϬϭͲϮ͕ŝŶƚŚĞũƵƌŝƐĚŝĐƚŝŽŶŝŶǁŚŝĐŚƚŚĞŶĞǁƐƚĂŶĚĂƌĚŝƐďĞĐŽŵŝŶŐĞĨĨĞĐƚŝǀĞ͘


>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
:ƵůLJ͕ϮϬϭϯ

ϯ

dŚĞƉƌŽƉŽƐĞĚƌĞǀŝƐĞĚĚĞĨŝŶŝƚŝŽŶĨŽƌ͞/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͟ŝƐŝŶĐŽƌƉŽƌĂƚĞĚŝŶƚŚĞEZĂƉƉƌŽǀĞĚƐƚĂŶĚĂƌĚƐ͕
ĚĞƚĂŝůĞĚŝŶƚƚĂĐŚŵĞŶƚϭŽĨƚŚŝƐĚŽĐƵŵĞŶƚ͘

ƉƉůŝĐĂďůĞŶƚŝƚŝĞƐ
ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ
ZĞŐƵůĂƚŝŽŶZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ

ƉƉůŝĐĂďůĞ&ĂĐŝůŝƚŝĞƐ
Eͬ

ŽŶĨŽƌŵŝŶŐŚĂŶŐĞƐƚŽKƚŚĞƌ^ƚĂŶĚĂƌĚƐ
EŽŶĞ

ĨĨĞĐƚŝǀĞĂƚĞƐ
>ͲϬϬϭͲϮƐŚĂůůďĞĐŽŵĞĞĨĨĞĐƚŝǀĞĂƐĨŽůůŽǁƐ͗

&ŝƌƐƚĚĂLJŽĨƚŚĞĨŝƌƐƚĐĂůĞŶĚĂƌƋƵĂƌƚĞƌƚŚĂƚŝƐƚǁĞůǀĞŵŽŶƚŚƐďĞLJŽŶĚƚŚĞĚĂƚĞƚŚĂƚƚŚŝƐƐƚĂŶĚĂƌĚ
ŝƐ ĂƉƉƌŽǀĞĚ ďLJ ĂƉƉůŝĐĂďůĞ ƌĞŐƵůĂƚŽƌLJ ĂƵƚŚŽƌŝƚŝĞƐ͕ Žƌ ŝŶ ƚŚŽƐĞ ũƵƌŝƐĚŝĐƚŝŽŶƐ ǁŚĞƌĞ ƌĞŐƵůĂƚŽƌLJ
ĂƉƉƌŽǀĂů ŝƐ ŶŽƚ ƌĞƋƵŝƌĞĚ͕ ƚŚĞ ƐƚĂŶĚĂƌĚ ďĞĐŽŵĞƐ ĞĨĨĞĐƚŝǀĞ ƚŚĞ ĨŝƌƐƚ ĚĂLJ ŽĨ ƚŚĞ ĨŝƌƐƚ ĐĂůĞŶĚĂƌ
ƋƵĂƌƚĞƌƚŚĂƚŝƐƚǁĞůǀĞŵŽŶƚŚƐďĞLJŽŶĚƚŚĞĚĂƚĞƚŚŝƐƐƚĂŶĚĂƌĚŝƐĂƉƉƌŽǀĞĚďLJƚŚĞEZŽĂƌĚŽĨ
dƌƵƐƚĞĞƐ͕ Žƌ ĂƐ ŽƚŚĞƌǁŝƐĞ ŵĂĚĞ ĞĨĨĞĐƚŝǀĞ ƉƵƌƐƵĂŶƚ ƚŽ ƚŚĞ ůĂǁƐ ĂƉƉůŝĐĂďůĞ ƚŽ ƐƵĐŚ ZK
ŐŽǀĞƌŶŵĞŶƚĂůĂƵƚŚŽƌŝƚŝĞƐ͘ 

:ƵƐƚŝĨŝĐĂƚŝŽŶ
dŚĞƚǁĞůǀĞͲŵŽŶƚŚƉĞƌŝŽĚĨŽƌŝŵƉůĞŵĞŶƚĂƚŝŽŶŽĨ>ͲϬϬϭͲϮǁŝůůƉƌŽǀŝĚĞĂŵƉůĞƚŝŵĞĨŽƌĂůĂŶĐŝŶŐ
ƵƚŚŽƌŝƚŝĞƐƚŽŵĂŬĞŶĞĐĞƐƐĂƌLJŵŽĚŝĨŝĐĂƚŝŽŶƐƚŽĞdžŝƐƚŝŶŐƐŽĨƚǁĂƌĞƉƌŽŐƌĂŵƐƚŽƉĞƌĨŽƌŵƚŚĞ>
ĐĂůĐƵůĂƚŝŽŶƐĨŽƌĐŽŵƉůŝĂŶĐĞ͘

ZĞƚŝƌĞŵĞŶƚƐ
>ͲϬϬϭͲϬ͘ϭĂʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞƐŚŽƵůĚďĞƌĞƚŝƌĞĚĂƚŵŝĚŶŝŐŚƚŽĨƚŚĞĚĂLJ
ŝŵŵĞĚŝĂƚĞůLJƉƌŝŽƌƚŽƚŚĞĞĨĨĞĐƚŝǀĞĚĂƚĞŽĨ>ͲϬϬϭͲϮŝŶƚŚĞƉĂƌƚŝĐƵůĂƌũƵƌŝƐĚŝĐƚŝŽŶŝŶǁŚŝĐŚƚŚĞŶĞǁ
ƐƚĂŶĚĂƌĚŝƐďĞĐŽŵŝŶŐĞĨĨĞĐƚŝǀĞ͘


>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
:ƵůLJ͕ϮϬϭϯ

ϰ

ƚƚĂĐŚŵĞŶƚϭ
ƉƉƌŽǀĞĚ^ƚĂŶĚĂƌĚƐ/ŶĐŽƌƉŽƌĂƚŝŶŐƚŚĞdĞƌŵ͞/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͟

>ͲϬϬϭͲϬ͘ϭĂͶZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
>ͲϬϬϮͲϬͶŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
>ͲϬϬϮͲϭͶŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
>ͲϬϬϯͲϬ͘ϭďͶ&ƌĞƋƵĞŶĐLJZĞƐƉŽŶƐĞĂŶĚŝĂƐ
>ͲϬϬϰͲϬͶdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶ
>ͲϬϬϰͲϭͶdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶ
>ͲϬϬϰͲtͲϬϭͶƵƚŽŵĂƚŝĐdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶ
>ͲϬϬϱͲϬ͘ϭďͶƵƚŽŵĂƚŝĐ'ĞŶĞƌĂƚŝŽŶŽŶƚƌŽů
>ͲϬϬϲͲϮͶ/ŶĂĚǀĞƌƚĞŶƚ/ŶƚĞƌĐŚĂŶŐĞ
t^ƚĂŶĚĂƌĚ>Ͳ^dͲϬϬϮͲϭͲKƉĞƌĂƚŝŶŐZĞƐĞƌǀĞƐ
/WͲϬϬϭͲϭĂͶ^ĂďŽƚĂŐĞZĞƉŽƌƚŝŶŐ
/WͲϬϬϭͲϮĂͶ^ĂďŽƚĂŐĞZĞƉŽƌƚŝŶŐ
/WʹϬϬϮʹϰͶLJďĞƌ^ĞĐƵƌŝƚLJͶƌŝƚŝĐĂůLJďĞƌƐƐĞƚ/ĚĞŶƚŝĨŝĐĂƚŝŽŶ
/WʹϬϬϱʹϯĂͶLJďĞƌ^ĞĐƵƌŝƚLJͶůĞĐƚƌŽŶŝĐ^ĞĐƵƌŝƚLJWĞƌŝŵĞƚĞƌ;ƐͿ
KDͲϬϬϭͲϭ͘ϭͶdĞůĞĐŽŵŵƵŶŝĐĂƚŝŽŶƐ
KWͲϬϬϭͲϮďͶŵĞƌŐĞŶĐLJKƉĞƌĂƚŝŽŶƐWůĂŶŶŝŶŐ
KWͲϬϬϮͲϮ͘ϭͶĂƉĂĐŝƚLJĂŶĚŶĞƌŐLJŵĞƌŐĞŶĐŝĞƐ
KWͲϬϬϮͲϯͶĂƉĂĐŝƚLJĂŶĚŶĞƌŐLJŵĞƌŐĞŶĐŝĞƐ
KWͲϬϬϯͲϭͶ>ŽĂĚ^ŚĞĚĚŝŶŐWůĂŶƐ
KWͲϬϬϯͲϮͶ>ŽĂĚ^ŚĞĚĚŝŶŐWůĂŶƐ
KWͲϬϬϰͲϭͶŝƐƚƵƌďĂŶĐĞZĞƉŽƌƚŝŶŐ
KWͲϬϬϱͲϭͶ^LJƐƚĞŵZĞƐƚŽƌĂƚŝŽŶWůĂŶƐ
KWͲϬϬϱͲϮͶ^LJƐƚĞŵZĞƐƚŽƌĂƚŝŽŶĨƌŽŵůĂĐŬƐƚĂƌƚZĞƐŽƵƌĐĞƐ
KWͲϬϬϲͲϭͶZĞůŝĂďŝůŝƚLJŽŽƌĚŝŶĂƚŝŽŶͶ^LJƐƚĞŵZĞƐƚŽƌĂƚŝŽŶ
KWͲϬϬϲͲϮͶ^LJƐƚĞŵZĞƐƚŽƌĂƚŝŽŶŽŽƌĚŝŶĂƚŝŽŶ
&ͲϬϬϴͲϯͶ&ĂĐŝůŝƚLJZĂƚŝŶŐƐ
&ͲϬϭϬͲϮͶ^LJƐƚĞŵKƉĞƌĂƚŝŶŐ>ŝŵŝƚƐDĞƚŚŽĚŽůŽŐLJĨŽƌƚŚĞWůĂŶŶŝŶŐ,ŽƌŝnjŽŶ
&ͲϬϭϭͲϮͶ^LJƐƚĞŵKƉĞƌĂƚŝŶŐ>ŝŵŝƚƐDĞƚŚŽĚŽůŽŐLJĨŽƌƚŚĞKƉĞƌĂƚŝŽŶƐ,ŽƌŝnjŽŶ
/EdͲϬϬϱͲϯͶ/ŶƚĞƌĐŚĂŶŐĞƵƚŚŽƌŝƚLJŝƐƚƌŝďƵƚĞƐƌƌĂŶŐĞĚ/ŶƚĞƌĐŚĂŶŐĞ
/EdͲϬϬϲͲϯͶZĞƐƉŽŶƐĞƚŽ/ŶƚĞƌĐŚĂŶŐĞƵƚŚŽƌŝƚLJ
/EdͲϬϬϴͲϯͶ/ŶƚĞƌĐŚĂŶŐĞƵƚŚŽƌŝƚLJŝƐƚƌŝďƵƚĞƐ^ƚĂƚƵƐ
/ZKͲϬϬϭͲϭ͘ϭͶZĞůŝĂďŝůŝƚLJŽŽƌĚŝŶĂƚŝŽŶͶZĞƐƉŽŶƐŝďŝůŝƚŝĞƐĂŶĚƵƚŚŽƌŝƚŝĞƐ
/ZKͲϬϬϭͲϮͶZĞůŝĂďŝůŝƚLJŽŽƌĚŝŶĂƚŝŽŶͶZĞƐƉŽŶƐŝďŝůŝƚŝĞƐĂŶĚƵƚŚŽƌŝƚŝĞƐ
/ZKͲϬϬϮͲϭͶZĞůŝĂďŝůŝƚLJŽŽƌĚŝŶĂƚŝŽŶͶ&ĂĐŝůŝƚŝĞƐ
/ZKͲϬϬϮͲϮͶZĞůŝĂďŝůŝƚLJŽŽƌĚŝŶĂƚŝŽŶͶ&ĂĐŝůŝƚŝĞƐ
/ZKͲϬϬϰͲϭͶZĞůŝĂďŝůŝƚLJŽŽƌĚŝŶĂƚŝŽŶͶKƉĞƌĂƚŝŽŶƐWůĂŶŶŝŶŐ
/ZKͲϬϬϱͲϮĂͶZĞůŝĂďŝůŝƚLJŽŽƌĚŝŶĂƚŝŽŶͶƵƌƌĞŶƚĂLJKƉĞƌĂƚŝŽŶƐ

>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
:ƵůLJ͕ϮϬϭϯ

ϱ

/ZKͲϬϬϱͲϯĂͶZĞůŝĂďŝůŝƚLJŽŽƌĚŝŶĂƚŝŽŶͶƵƌƌĞŶƚĂLJKƉĞƌĂƚŝŽŶƐ
/ZKͲϬϬϲͲϱͶZĞůŝĂďŝůŝƚLJŽŽƌĚŝŶĂƚŝŽŶͶdƌĂŶƐŵŝƐƐŝŽŶ>ŽĂĚŝŶŐZĞůŝĞĨ
/ZKͲϬϬϲͲ^dͲϭͶd>ZWƌŽĐĞĚƵƌĞĨŽƌƚŚĞĂƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ
/ZKͲϬϭϰͲϭͶWƌŽĐĞĚƵƌĞƐ͕WƌŽĐĞƐƐĞƐ͕ŽƌWůĂŶƐƚŽ^ƵƉƉŽƌƚŽŽƌĚŝŶĂƚŝŽŶĞƚǁĞĞŶ
ZĞůŝĂďŝůŝƚLJŽŽƌĚŝŶĂƚŽƌƐ
/ZKͲϬϭϰͲϮͶŽŽƌĚŝŶĂƚŝŽŶŵŽŶŐZĞůŝĂďŝůŝƚLJŽŽƌĚŝŶĂƚŽƌƐ
/ZKͲϬϭϱͲϭͶEŽƚŝĨŝĐĂƚŝŽŶƐĂŶĚ/ŶĨŽƌŵĂƚŝŽŶdžĐŚĂŶŐĞĞƚǁĞĞŶZĞůŝĂďŝůŝƚLJŽŽƌĚŝŶĂƚŽƌƐ
/ZKͲϬϭϲͲϭͶŽŽƌĚŝŶĂƚŝŽŶŽĨZĞĂůͲƚŝŵĞĐƚŝǀŝƚŝĞƐĞƚǁĞĞŶZĞůŝĂďŝůŝƚLJŽŽƌĚŝŶĂƚŽƌƐ
DKͲϬϭϬͲϬͶ^ƚĞĂĚLJͲ^ƚĂƚĞĂƚĂĨŽƌdƌĂŶƐŵŝƐƐŝŽŶ^LJƐƚĞŵDŽĚĞůŝŶŐĂŶĚ^ŝŵƵůĂƚŝŽŶ
DKͲϬϭϭͲϬͶZĞŐŝŽŶĂů^ƚĞĂĚLJͲ^ƚĂƚĞĂƚĂZĞƋƵŝƌĞŵĞŶƚƐĂŶĚZĞƉŽƌƚŝŶŐWƌŽĐĞĚƵƌĞƐ
DKͲϬϭϮͲϬͶLJŶĂŵŝĐƐĂƚĂĨŽƌdƌĂŶƐŵŝƐƐŝŽŶ^LJƐƚĞŵDŽĚĞůŝŶŐĂŶĚ^ŝŵƵůĂƚŝŽŶ
DKͲϬϭϯͲϭͶZZKLJŶĂŵŝĐƐĂƚĂZĞƋƵŝƌĞŵĞŶƚƐĂŶĚZĞƉŽƌƚŝŶŐWƌŽĐĞĚƵƌĞƐ
DKͲϬϭϰͲϬͶĞǀĞůŽƉŵĞŶƚŽĨ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶͲ^ƉĞĐŝĨŝĐ^ƚĞĂĚLJ^ƚĂƚĞ^LJƐƚĞŵDŽĚĞůƐ
DKͲϬϭϱͲϬͶĞǀĞůŽƉŵĞŶƚŽĨ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶͲ^ƉĞĐŝĨŝĐLJŶĂŵŝĐƐ^LJƐƚĞŵDŽĚĞůƐ
DKͲϬϭϱͲϬ͘ϭͶĞǀĞůŽƉŵĞŶƚŽĨ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶͲ^ƉĞĐŝĨŝĐLJŶĂŵŝĐƐ^LJƐƚĞŵ
DŽĚĞůƐ
DKͲϬϯϬͲϬϮͶ&ůŽǁŐĂƚĞDĞƚŚŽĚŽůŽŐLJ
WZͲϬϬϭͲϭͶ^LJƐƚĞŵWƌŽƚĞĐƚŝŽŶŽŽƌĚŝŶĂƚŝŽŶ
WZͲϬϬϲͲϭͶƵƚŽŵĂƚŝĐhŶĚĞƌĨƌĞƋƵĞŶĐLJ>ŽĂĚ^ŚĞĚĚŝŶŐ
dKWͲϬϬϮͲϮĂͶEŽƌŵĂůKƉĞƌĂƚŝŽŶƐWůĂŶŶŝŶŐ
dKWͲϬϬϰͲϮͶdƌĂŶƐŵŝƐƐŝŽŶKƉĞƌĂƚŝŽŶƐ
dKWͲϬϬϱͲϭ͘ϭĂͶKƉĞƌĂƚŝŽŶĂůZĞůŝĂďŝůŝƚLJ/ŶĨŽƌŵĂƚŝŽŶ
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ƉƉƌŽǀĂůƐZĞƋƵŝƌĞĚ
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EŽŶĞ

ZĞǀŝƐŝŽŶƐƚŽ'ůŽƐƐĂƌLJdĞƌŵƐ
dŚĞĨŽůůŽǁŝŶŐĚĞĨŝŶŝƚŝŽŶƐƐŚĂůůďĞĐŽŵĞĞĨĨĞĐƚŝǀĞǁŚĞŶ>ͲϬϬϭͲϮďĞĐŽŵĞƐĞĨĨĞĐƚŝǀĞ͗

ZĞŐƵůĂƚŝŽŶZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ͗ŐƌŽƵƉǁŚŽƐĞŵĞŵďĞƌƐĐŽŶƐŝƐƚŽĨƚǁŽŽƌŵŽƌĞĂůĂŶĐŝŶŐ
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ZĞŐƵůĂƚŝŽŶZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉZĞƉŽƌƚŝŶŐ͗ƚĂŶLJŐŝǀĞŶƚŝŵĞŽĨŵĞĂƐƵƌĞŵĞŶƚĨŽƌƚŚĞ
ĂƉƉůŝĐĂďůĞZĞŐƵůĂƚŝŽŶZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ͕ƚŚĞĂůŐĞďƌĂŝĐƐƵŵŽĨƚŚĞZĞƉŽƌƚŝŶŐƐ;Žƌ
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ZĞƉŽƌƚŝŶŐ͗dŚĞƐĐĂŶƌĂƚĞǀĂůƵĞƐŽĨĂĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛ƐƌĞĂŽŶƚƌŽůƌƌŽƌ;Ϳ
ŵĞĂƐƵƌĞĚŝŶDt͕ǁŚŝĐŚŝŶĐůƵĚĞƐƚŚĞĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛ƐEŶĞƚ
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ĂŶLJŬŶŽǁŶŵĞƚĞƌĞƌƌŽƌ͘/ŶƚŚĞtĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͕ZĞƉŽƌƚŝŶŐŝŶĐůƵĚĞƐƵƚŽŵĂƚŝĐ
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ZĞƉŽƌƚŝŶŐŝƐĐĂůĐƵůĂƚĞĚĂƐĨŽůůŽǁƐ͗

ZĞƉŽƌƚŝŶŐс;E/оE/^ͿоϭϬ;&о&^Ϳо/D

ZĞƉŽƌƚŝŶŐŝƐĐĂůĐƵůĂƚĞĚŝŶƚŚĞtĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶĂƐĨŽůůŽǁƐ͗

ZĞƉŽƌƚŝŶŐс;E/оE/^ͿоϭϬ;&о&^Ϳо/Dн/d


tŚĞƌĞ͗
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ĂƐLJŶĐŚƌŽŶŽƵƐƚŝĞƐƚŽĂŶŽƚŚĞƌ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶŵĂLJŝŶĐůƵĚĞŽƌĞdžĐůƵĚĞŵĞŐĂǁĂƚƚ
ƚƌĂŶƐĨĞƌƐŽŶƚŚŽƐĞdƚŝĞ>ůŝŶĞƐŝŶƚŚĞŝƌĂĐƚƵĂůŝŶƚĞƌĐŚĂŶŐĞ͕ƉƌŽǀŝĚĞĚƚŚĞLJĂƌĞ
ŝŵƉůĞŵĞŶƚĞĚŝŶƚŚĞƐĂŵĞŵĂŶŶĞƌĨŽƌEĞƚ/ŶƚĞƌĐŚĂŶŐĞ^ĐŚĞĚƵůĞ͘
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ƚƌĂŶƐĨĞƌƐ͕ŝŶĐůƵĚŝŶŐLJŶĂŵŝĐ^ĐŚĞĚƵůĞƐ͕ǁŝƚŚĂĚũĂĐĞŶƚĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐ͕ĂŶĚƚĂŬŝŶŐ
ŝŶƚŽĂĐĐŽƵŶƚƚŚĞĞĨĨĞĐƚƐŽĨƐĐŚĞĚƵůĞƌĂŵƉƐ͘ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐĚŝƌĞĐƚůLJĐŽŶŶĞĐƚĞĚǀŝĂ
ĂƐLJŶĐŚƌŽŶŽƵƐƚŝĞƐƚŽĂŶŽƚŚĞƌ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶŵĂLJŝŶĐůƵĚĞŽƌĞdžĐůƵĚĞŵĞŐĂǁĂƚƚ
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ŝŵƉůĞŵĞŶƚĞĚŝŶƚŚĞƐĂŵĞŵĂŶŶĞƌĨŽƌEĞƚ/ŶƚĞƌĐŚĂŶŐĞĐƚƵĂů͘
;&ƌĞƋƵĞŶĐLJŝĂƐ^ĞƚƚŝŶŐͿŝƐƚŚĞ&ƌĞƋƵĞŶĐLJŝĂƐ^ĞƚƚŝŶŐ;ŝŶŶĞŐĂƚŝǀĞDtͬϬ͘ϭ,njͿĨŽƌƚŚĞ
ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͘
ϭϬŝƐƚŚĞĐŽŶƐƚĂŶƚĨĂĐƚŽƌƚŚĂƚĐŽŶǀĞƌƚƐƚŚĞĨƌĞƋƵĞŶĐLJďŝĂƐƐĞƚƚŝŶŐƵŶŝƚƐƚŽDtͬ,nj͘
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&^;^ĐŚĞĚƵůĞĚ&ƌĞƋƵĞŶĐLJͿŝƐϲϬ͘Ϭ,nj͕ĞdžĐĞƉƚĚƵƌŝŶŐĂƚŝŵĞĐŽƌƌĞĐƚŝŽŶ͘
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ĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶƚŚĞŝŶƚĞŐƌĂƚĞĚŚŽƵƌůLJĂǀĞƌĂŐĞŽĨƚŚĞŶĞƚŝŶƚĞƌĐŚĂŶŐĞĂĐƚƵĂů;E/Ϳ
ĂŶĚƚŚĞĐƵŵƵůĂƚŝǀĞŚŽƵƌůLJŶĞƚ/ŶƚĞƌĐŚĂŶŐĞĞŶĞƌŐLJŵĞĂƐƵƌĞŵĞŶƚ;ŝŶŵĞŐĂǁĂƚƚͲŚŽƵƌƐͿ͘
/d;ƵƚŽŵĂƚŝĐdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶͿŝƐƚŚĞĂĚĚŝƚŝŽŶŽĨĂĐŽŵƉŽŶĞŶƚƚŽƚŚĞ
ĞƋƵĂƚŝŽŶĨŽƌƚŚĞtĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶƚŚĂƚŵŽĚŝĨŝĞƐƚŚĞĐŽŶƚƌŽůƉŽŝŶƚĨŽƌƚŚĞ
ƉƵƌƉŽƐĞŽĨĐŽŶƚŝŶƵŽƵƐůLJƉĂLJŝŶŐďĂĐŬWƌŝŵĂƌLJ/ŶĂĚǀĞƌƚĞŶƚ/ŶƚĞƌĐŚĂŶŐĞƚŽĐŽƌƌĞĐƚ
ĂĐĐƵŵƵůĂƚĞĚƚŝŵĞĞƌƌŽƌ͘ƵƚŽŵĂƚŝĐdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶŝƐŽŶůLJĂƉƉůŝĐĂďůĞŝŶƚŚĞ
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ǁŚĞŶŽƉĞƌĂƚŝŶŐŝŶƵƚŽŵĂƚŝĐdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶĐŽŶƚƌŽůŵŽĚĞ͘

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ȴdŝƐƚŚĞŚŽƵƌůLJĐŚĂŶŐĞŝŶƐLJƐƚĞŵdŝŵĞƌƌŽƌĂƐĚŝƐƚƌŝďƵƚĞĚďLJƚŚĞ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ
dŝŵĞDŽŶŝƚŽƌ͘tŚĞƌĞ͗



ȴdсdĞŶĚŚŽƵƌʹdďĞŐŝŶŚŽƵƌʹdĂĚũʹ;ƚͿΎ;dŽĨĨƐĞƚͿ

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•

ƚŝƐƚŚĞŶƵŵďĞƌŽĨŵŝŶƵƚĞƐŽĨDĂŶƵĂůdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶƚŚĂƚŽĐĐƵƌƌĞĚĚƵƌŝŶŐƚŚĞ
ŚŽƵƌ͘

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dŽĨĨƐĞƚŝƐϬ͘ϬϬϬŽƌнϬ͘ϬϮϬŽƌͲϬ͘ϬϮϬ͘

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W//ĂĐĐƵŵŝƐƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛ƐĂĐĐƵŵƵůĂƚĞĚW//ŚŽƵƌůLJŝŶDtŚ͘ŶKŶͲWĞĂŬĂŶĚ
KĨĨͲWĞĂŬĂĐĐƵŵƵůĂƚŝŽŶĂĐĐŽƵŶƚŝŶŐŝƐƌĞƋƵŝƌĞĚ͘
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on/off peak
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on/off peak

PII

accum

нW//ŚŽƵƌůLJ



ůůEZ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶƐǁŝƚŚŵƵůƚŝƉůĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐŽƉĞƌĂƚĞƵƐŝŶŐƚŚĞƉƌŝŶĐŝƉůĞƐ
ŽĨdŝĞͲůŝŶĞŝĂƐ;d>ͿŽŶƚƌŽůĂŶĚƌĞƋƵŝƌĞƚŚĞƵƐĞŽĨĂŶĞƋƵĂƚŝŽŶƐŝŵŝůĂƌƚŽƚŚĞZĞƉŽƌƚŝŶŐ
ĚĞĨŝŶĞĚĂďŽǀĞ͘ŶLJŵŽĚŝĨŝĐĂƚŝŽŶ;ƐͿƚŽƚŚŝƐƐƉĞĐŝĨŝĞĚZĞƉŽƌƚŝŶŐĞƋƵĂƚŝŽŶƚŚĂƚ
ŝƐ;ĂƌĞͿŝŵƉůĞŵĞŶƚĞĚĨŽƌĂůůƐŽŶĂŶŝ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶĂŶĚŝƐ;ĂƌĞͿĐŽŶƐŝƐƚĞŶƚǁŝƚŚƚŚĞ
ĨŽůůŽǁŝŶŐĨŽƵƌƉƌŝŶĐŝƉůĞƐǁŝůůƉƌŽǀŝĚĞĂǀĂůŝĚĂůƚĞƌŶĂƚŝǀĞZĞƉŽƌƚŝŶŐĞƋƵĂƚŝŽŶĐŽŶƐŝƐƚĞŶƚ
ǁŝƚŚƚŚĞŵĞĂƐƵƌĞƐŝŶĐůƵĚĞĚŝŶƚŚŝƐƐƚĂŶĚĂƌĚ͘
ϭ͘ ůůƉŽƌƚŝŽŶƐŽĨƚŚĞ/ŝŶƚĞƌĐŽŶŶĞĐƚŝŽŶĂƌĞŝŶĐůƵĚĞĚŝŶŽŶĞĂƌĞĂŽƌĂŶŽƚŚĞƌƐŽƚŚĂƚƚŚĞ
ƐƵŵŽĨĂůůĂƌĞĂŐĞŶĞƌĂƚŝŽŶ͕ůŽĂĚƐĂŶĚůŽƐƐĞƐŝƐƚŚĞƐĂŵĞĂƐƚŽƚĂůƐLJƐƚĞŵŐĞŶĞƌĂƚŝŽŶ͕
ůŽĂĚĂŶĚůŽƐƐĞƐ͘
Ϯ͘ dŚĞĂůŐĞďƌĂŝĐƐƵŵŽĨĂůůĂƌĞĂEŶĞƚ/ŝŶƚĞƌĐŚĂŶŐĞ^ƐĐŚĞĚƵůĞƐĂŶĚĂůůEŶĞƚ/ŝŶƚĞƌĐŚĂŶŐĞ
ĂĐƚƵĂůǀĂůƵĞƐŝƐĞƋƵĂůƚŽnjĞƌŽĂƚĂůůƚŝŵĞƐ͘
ϯ͘ dŚĞƵƐĞŽĨĂĐŽŵŵŽŶ^ƐĐŚĞĚƵůĞĚ&ĨƌĞƋƵĞŶĐLJ&^ĨŽƌĂůůĂƌĞĂƐĂƚĂůůƚŝŵĞƐ͘
ϰ͘ dŚĞĂďƐĞŶĐĞŽĨŵĞƚĞƌŝŶŐŽƌĐŽŵƉƵƚĂƚŝŽŶĂůĞƌƌŽƌƐ͘;dŚĞŝŶĐůƵƐŝŽŶĂŶĚƵƐĞŽĨƚŚĞ/D
ƚĞƌŵƚŽĂĐĐŽƵŶƚĨŽƌŬŶŽǁŶŵĞƚĞƌŝŶŐŽƌĐŽŵƉƵƚĂƚŝŽŶĂůĞƌƌŽƌƐ͘Ϳ
/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͗tŚĞŶĐĂƉŝƚĂůŝnjĞĚ͕ĂŶLJŽŶĞŽĨƚŚĞĨŽƵƌŵĂũŽƌĞůĞĐƚƌŝĐƐLJƐƚĞŵŶĞƚǁŽƌŬƐŝŶEŽƌƚŚ
ŵĞƌŝĐĂ͗ĂƐƚĞƌŶ͕tĞƐƚĞƌŶ͕ZKdĂŶĚYƵĞďĞĐ͘

dŚĞĞdžŝƐƚŝŶŐĚĞĨŝŶŝƚŝŽŶŽĨ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶƐŚŽƵůĚďĞƌĞƚŝƌĞĚĂƚŵŝĚŶŝŐŚƚŽĨƚŚĞĚĂLJŝŵŵĞĚŝĂƚĞůLJƉƌŝŽƌƚŽ
ƚŚĞĞĨĨĞĐƚŝǀĞĚĂƚĞŽĨ>ͲϬϬϭͲϮ͕ŝŶƚŚĞũƵƌŝƐĚŝĐƚŝŽŶŝŶǁŚŝĐŚƚŚĞŶĞǁƐƚĂŶĚĂƌĚŝƐďĞĐŽŵŝŶŐĞĨĨĞĐƚŝǀĞ͘


>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
:ƵůLJ͕ϮϬϭϯ

ϯ

dŚĞƉƌŽƉŽƐĞĚƌĞǀŝƐĞĚĚĞĨŝŶŝƚŝŽŶĨŽƌ͞/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͟ŝƐŝŶĐŽƌƉŽƌĂƚĞĚŝŶƚŚĞEZĂƉƉƌŽǀĞĚƐƚĂŶĚĂƌĚƐ͕
ĚĞƚĂŝůĞĚŝŶƚƚĂĐŚŵĞŶƚϭŽĨƚŚŝƐĚŽĐƵŵĞŶƚ͘

ƉƉůŝĐĂďůĞŶƚŝƚŝĞƐ
ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ
ZĞŐƵůĂƚŝŽŶZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ

ƉƉůŝĐĂďůĞ&ĂĐŝůŝƚŝĞƐ
Eͬ

ŽŶĨŽƌŵŝŶŐŚĂŶŐĞƐƚŽKƚŚĞƌ^ƚĂŶĚĂƌĚƐ
EŽŶĞ

ĨĨĞĐƚŝǀĞĂƚĞƐ
>ͲϬϬϭͲϮƐŚĂůůďĞĐŽŵĞĞĨĨĞĐƚŝǀĞĂƐĨŽůůŽǁƐ͗

&ŝƌƐƚ ĚĂLJ ŽĨ ƚŚĞ ĨŝƌƐƚ ĐĂůĞŶĚĂƌ ƋƵĂƌƚĞƌ ƚŚĂƚ ŝƐ ƚǁĞůǀĞƐŝdž ŵŽŶƚŚƐ ďĞLJŽŶĚ ƚŚĞ ĚĂƚĞ ƚŚĂƚ ƚŚŝƐ
ƐƚĂŶĚĂƌĚ ŝƐ ĂƉƉƌŽǀĞĚ ďLJ ĂƉƉůŝĐĂďůĞ ƌĞŐƵůĂƚŽƌLJ ĂƵƚŚŽƌŝƚŝĞƐ͕ Žƌ ŝŶ ƚŚŽƐĞ ũƵƌŝƐĚŝĐƚŝŽŶƐ ǁŚĞƌĞ
ƌĞŐƵůĂƚŽƌLJ ĂƉƉƌŽǀĂů ŝƐ ŶŽƚ ƌĞƋƵŝƌĞĚ͕ ƚŚĞ ƐƚĂŶĚĂƌĚ ďĞĐŽŵĞƐ ĞĨĨĞĐƚŝǀĞ ƚŚĞ ĨŝƌƐƚ ĚĂLJ ŽĨ ƚŚĞ ĨŝƌƐƚ
ĐĂůĞŶĚĂƌ ƋƵĂƌƚĞƌ ƚŚĂƚ ŝƐ ƚǁĞůǀĞƐŝdž ŵŽŶƚŚƐ ďĞLJŽŶĚ ƚŚĞ ĚĂƚĞ ƚŚŝƐ ƐƚĂŶĚĂƌĚ ŝƐ ĂƉƉƌŽǀĞĚ ďLJ ƚŚĞ
EZŽĂƌĚŽĨdƌƵƐƚĞĞƐ͕ŽƌĂƐŽƚŚĞƌǁŝƐĞŵĂĚĞĞĨĨĞĐƚŝǀĞƉƵƌƐƵĂŶƚƚŽƚŚĞůĂǁƐĂƉƉůŝĐĂďůĞƚŽƐƵĐŚ
ZKŐŽǀĞƌŶŵĞŶƚĂůĂƵƚŚŽƌŝƚŝĞƐ͘


:ƵƐƚŝĨŝĐĂƚŝŽŶ
dŚĞƚǁĞůǀĞƐŝdžͲŵŽŶƚŚƉĞƌŝŽĚĨŽƌŝŵƉůĞŵĞŶƚĂƚŝŽŶŽĨ>ͲϬϬϭͲϮǁŝůůƉƌŽǀŝĚĞĂŵƉůĞƚŝŵĞĨŽƌĂůĂŶĐŝŶŐ
ƵƚŚŽƌŝƚŝĞƐƚŽŵĂŬĞŶĞĐĞƐƐĂƌLJŵŽĚŝĨŝĐĂƚŝŽŶƐƚŽĞdžŝƐƚŝŶŐƐŽĨƚǁĂƌĞƉƌŽŐƌĂŵƐƚŽƉĞƌĨŽƌŵƚŚĞ>
ĐĂůĐƵůĂƚŝŽŶƐĨŽƌĐŽŵƉůŝĂŶĐĞ͘

ZĞƚŝƌĞŵĞŶƚƐ
>ͲϬϬϭͲϬ͘ϭĂʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞƐŚŽƵůĚďĞƌĞƚŝƌĞĚĂƚŵŝĚŶŝŐŚƚŽĨƚŚĞĚĂLJ
ŝŵŵĞĚŝĂƚĞůLJƉƌŝŽƌƚŽƚŚĞĞĨĨĞĐƚŝǀĞĚĂƚĞŽĨ>ͲϬϬϭͲϮŝŶƚŚĞƉĂƌƚŝĐƵůĂƌũƵƌŝƐĚŝĐƚŝŽŶŝŶǁŚŝĐŚƚŚĞŶĞǁ
ƐƚĂŶĚĂƌĚŝƐďĞĐŽŵŝŶŐĞĨĨĞĐƚŝǀĞ͘


>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
:ƵůLJ͕ϮϬϭϯ

ϰ

ƚƚĂĐŚŵĞŶƚϭ
ƉƉƌŽǀĞĚ^ƚĂŶĚĂƌĚƐ/ŶĐŽƌƉŽƌĂƚŝŶŐƚŚĞdĞƌŵ͞/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͟

>ͲϬϬϭͲϬ͘ϭĂͶZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
>ͲϬϬϮͲϬͶŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
>ͲϬϬϮͲϭͶŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
>ͲϬϬϯͲϬ͘ϭďͶ&ƌĞƋƵĞŶĐLJZĞƐƉŽŶƐĞĂŶĚŝĂƐ
>ͲϬϬϰͲϬͶdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶ
>ͲϬϬϰͲϭͶdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶ
>ͲϬϬϰͲtͲϬϭͶƵƚŽŵĂƚŝĐdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶ
>ͲϬϬϱͲϬ͘ϭďͶƵƚŽŵĂƚŝĐ'ĞŶĞƌĂƚŝŽŶŽŶƚƌŽů
>ͲϬϬϲͲϮͶ/ŶĂĚǀĞƌƚĞŶƚ/ŶƚĞƌĐŚĂŶŐĞ
t^ƚĂŶĚĂƌĚ>Ͳ^dͲϬϬϮͲϭͲKƉĞƌĂƚŝŶŐZĞƐĞƌǀĞƐ
/WͲϬϬϭͲϭĂͶ^ĂďŽƚĂŐĞZĞƉŽƌƚŝŶŐ
/WͲϬϬϭͲϮĂͶ^ĂďŽƚĂŐĞZĞƉŽƌƚŝŶŐ
/WʹϬϬϮʹϰͶLJďĞƌ^ĞĐƵƌŝƚLJͶƌŝƚŝĐĂůLJďĞƌƐƐĞƚ/ĚĞŶƚŝĨŝĐĂƚŝŽŶ
/WʹϬϬϱʹϯĂͶLJďĞƌ^ĞĐƵƌŝƚLJͶůĞĐƚƌŽŶŝĐ^ĞĐƵƌŝƚLJWĞƌŝŵĞƚĞƌ;ƐͿ
KDͲϬϬϭͲϭ͘ϭͶdĞůĞĐŽŵŵƵŶŝĐĂƚŝŽŶƐ
KWͲϬϬϭͲϮďͶŵĞƌŐĞŶĐLJKƉĞƌĂƚŝŽŶƐWůĂŶŶŝŶŐ
KWͲϬϬϮͲϮ͘ϭͶĂƉĂĐŝƚLJĂŶĚŶĞƌŐLJŵĞƌŐĞŶĐŝĞƐ
KWͲϬϬϮͲϯͶĂƉĂĐŝƚLJĂŶĚŶĞƌŐLJŵĞƌŐĞŶĐŝĞƐ
KWͲϬϬϯͲϭͶ>ŽĂĚ^ŚĞĚĚŝŶŐWůĂŶƐ
KWͲϬϬϯͲϮͶ>ŽĂĚ^ŚĞĚĚŝŶŐWůĂŶƐ
KWͲϬϬϰͲϭͶŝƐƚƵƌďĂŶĐĞZĞƉŽƌƚŝŶŐ
KWͲϬϬϱͲϭͶ^LJƐƚĞŵZĞƐƚŽƌĂƚŝŽŶWůĂŶƐ
KWͲϬϬϱͲϮͶ^LJƐƚĞŵZĞƐƚŽƌĂƚŝŽŶĨƌŽŵůĂĐŬƐƚĂƌƚZĞƐŽƵƌĐĞƐ
KWͲϬϬϲͲϭͶZĞůŝĂďŝůŝƚLJŽŽƌĚŝŶĂƚŝŽŶͶ^LJƐƚĞŵZĞƐƚŽƌĂƚŝŽŶ
KWͲϬϬϲͲϮͶ^LJƐƚĞŵZĞƐƚŽƌĂƚŝŽŶŽŽƌĚŝŶĂƚŝŽŶ
&ͲϬϬϴͲϯͶ&ĂĐŝůŝƚLJZĂƚŝŶŐƐ
&ͲϬϭϬͲϮͶ^LJƐƚĞŵKƉĞƌĂƚŝŶŐ>ŝŵŝƚƐDĞƚŚŽĚŽůŽŐLJĨŽƌƚŚĞWůĂŶŶŝŶŐ,ŽƌŝnjŽŶ
&ͲϬϭϭͲϮͶ^LJƐƚĞŵKƉĞƌĂƚŝŶŐ>ŝŵŝƚƐDĞƚŚŽĚŽůŽŐLJĨŽƌƚŚĞKƉĞƌĂƚŝŽŶƐ,ŽƌŝnjŽŶ
/EdͲϬϬϱͲϯͶ/ŶƚĞƌĐŚĂŶŐĞƵƚŚŽƌŝƚLJŝƐƚƌŝďƵƚĞƐƌƌĂŶŐĞĚ/ŶƚĞƌĐŚĂŶŐĞ
/EdͲϬϬϲͲϯͶZĞƐƉŽŶƐĞƚŽ/ŶƚĞƌĐŚĂŶŐĞƵƚŚŽƌŝƚLJ
/EdͲϬϬϴͲϯͶ/ŶƚĞƌĐŚĂŶŐĞƵƚŚŽƌŝƚLJŝƐƚƌŝďƵƚĞƐ^ƚĂƚƵƐ
/ZKͲϬϬϭͲϭ͘ϭͶZĞůŝĂďŝůŝƚLJŽŽƌĚŝŶĂƚŝŽŶͶZĞƐƉŽŶƐŝďŝůŝƚŝĞƐĂŶĚƵƚŚŽƌŝƚŝĞƐ
/ZKͲϬϬϭͲϮͶZĞůŝĂďŝůŝƚLJŽŽƌĚŝŶĂƚŝŽŶͶZĞƐƉŽŶƐŝďŝůŝƚŝĞƐĂŶĚƵƚŚŽƌŝƚŝĞƐ
/ZKͲϬϬϮͲϭͶZĞůŝĂďŝůŝƚLJŽŽƌĚŝŶĂƚŝŽŶͶ&ĂĐŝůŝƚŝĞƐ
/ZKͲϬϬϮͲϮͶZĞůŝĂďŝůŝƚLJŽŽƌĚŝŶĂƚŝŽŶͶ&ĂĐŝůŝƚŝĞƐ
/ZKͲϬϬϰͲϭͶZĞůŝĂďŝůŝƚLJŽŽƌĚŝŶĂƚŝŽŶͶKƉĞƌĂƚŝŽŶƐWůĂŶŶŝŶŐ
/ZKͲϬϬϱͲϮĂͶZĞůŝĂďŝůŝƚLJŽŽƌĚŝŶĂƚŝŽŶͶƵƌƌĞŶƚĂLJKƉĞƌĂƚŝŽŶƐ

>ͲϬϬϭͲϮʹZĞĂůWŽǁĞƌĂůĂŶĐŝŶŐŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞ
:ƵůLJ͕ϮϬϭϯ

ϱ

/ZKͲϬϬϱͲϯĂͶZĞůŝĂďŝůŝƚLJŽŽƌĚŝŶĂƚŝŽŶͶƵƌƌĞŶƚĂLJKƉĞƌĂƚŝŽŶƐ
/ZKͲϬϬϲͲϱͶZĞůŝĂďŝůŝƚLJŽŽƌĚŝŶĂƚŝŽŶͶdƌĂŶƐŵŝƐƐŝŽŶ>ŽĂĚŝŶŐZĞůŝĞĨ
/ZKͲϬϬϲͲ^dͲϭͶd>ZWƌŽĐĞĚƵƌĞĨŽƌƚŚĞĂƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ
/ZKͲϬϭϰͲϭͶWƌŽĐĞĚƵƌĞƐ͕WƌŽĐĞƐƐĞƐ͕ŽƌWůĂŶƐƚŽ^ƵƉƉŽƌƚŽŽƌĚŝŶĂƚŝŽŶĞƚǁĞĞŶ
ZĞůŝĂďŝůŝƚLJŽŽƌĚŝŶĂƚŽƌƐ
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ϲ

BAL-001-2 – Real Power
Balancing Control
Performance Standard
Background Document
July 2013

3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Table of Contents

Table of Contents
Table of Contents ............................................................................................................................ 2
Introduction .................................................................................................................................... 3
Background and Rationale by Requirement ................................................................................... 4
Requirement 1 ............................................................................................................................ 4
Requirement 2 ............................................................................................................................ 5

BAL-001-2 - Background Document
July, 2013

2

Real Power Balancing Control Performance Standard Background Document

Introduction
This document provides background on the development, testing, and implementation of BAL001-2 - Real Power Balancing Control Standard. The intent is to explain the rationale and
considerations for the requirements and their associated compliance information.
The original work for this standard was done by the Balancing Authority Controls standard
drafting team, which later joined with the Reliability-based Control Standard drafting team.
These combined teams were renamed Balance Authority Reliability-based Control standard
drafting team (BARC SDT).
The purpose of proposed Standard BAL-001-2 is to maintain Interconnection frequency within
predefined frequency limits. This draft standard defines Balancing Authority ACE Limit (BAAL),
and required the Balancing Authority (BA) to balance its resources and demand in Real-time so
that its clock-minute average of its Area Control Error (ACE) does not exceed its BAAL for more
than 30 consecutive clock-minutes.
As a proof of concept for the proposed BAAL standard, a BAAL field trial was approved by the
NERC Standards Committee and the Operating Committee. Currently participating in the field
trial are 13 Balancing Authorities in the Eastern Interconnection, 26 Balancing Authorities in the
Western Interconnection, the ERCOT Balancing Authority, and Quebec. Reliability Coordinators
for all Interconnections continue to monitor the performance of those participating Balancing
Authorities and provide information to support monthly analysis of the BAAL field trial. As of
the end of September 2011, no reliability issues with the BAAL field trial have been identified by
any Reliability Coordinator. The Western Interconnection has experienced changes during the
field trial with potential degradation to transmission; however, no explicit linkage has been
determined between the field trial and these degradations. For further information on the
results of the Western Interconnection, please refer to the WECC Reliability-based Control Field
Trial Report.
Historical Significance
A1-A2 Control Performance Policy was implemented in 1973 as:
A1 required the Balancing Authority’s ACE to return to zero within 10 minutes of previous
zero.
A2 required that the Balancing Authority’s averaged ACE for each 10-minute period must be
within limits.
A1-A2 had three main short comings:
ƒ Lack of theoretical justification
ƒ Large ACE treated the same as a small ACE, regardless of direction
ƒ Independent of Interconnection frequency
In 1996, a new NERC policy was approved which used CPS1, CPS2, and DCS.
CPS1is a:
BAL-001-2 - Background Document
July, 2013

3

Real Power Balancing Control Performance Standard Background Document
Statistical measure of ACE variability
Measure of ACE in combination with the Interconnection’s frequency error
Based on an equation derived from frequency-based statistical theory
CPS2 is:
Designed to limit a Control Area’s (now known as a Balancing Authority)
unscheduled power flows
Similar to the old A2 criteria
The proposed BAL-001-2 retains CPS1, but proposes a new measure BAAL to replace CPS2.
Currently CPS2:
Does not have a frequency component.
CPS2 many times give the Balancing Authority the indication to move their ACE
opposite to what will help frequency.
Only requires Balancing Authorities to comply 90 percent of the time as a minimum.

Background and Rationale by Requirement
Requirement 1
R1. The Responsible Entity shall operate such that the Control Performance Standard 1
(CPS1), calculated in accordance with Attachment 1, is greater than or equal to 100
percent for the applicable Interconnection in which it operates for each preceding 12
consecutive calendar month period, evaluated monthly.
Background and Rationale
Requirement R1 is not a new requirement. It is a restatement of the current BAL-001-0.1a
Requirement R1 with its equation and explanation of its individual components moved to an
attachment, Attachment 1 - Equations Supporting Requirement R1 and Measure M1. This
requirement is commonly referred to as Control Performance Standard 1 (CPS1). R1 is intended
to measure how well a Balancing Authority is able to control its generation and load
management programs, as measured by its Area Control Error (ACE), to support its
Interconnection’s frequency over a rolling one-year period.
CPS1 is a measure of a Balancing Authority’s control performance as it relates to its generation,
Load management, and Interconnection frequency when measured in one-minute averages
over a rolling one-year period. If all Balancing Authorities on an Interconnection are compliant
with the CPS1 measure, then the Interconnection will have a root mean square (RMS)
frequency error less than the Interconnection’s Epsilon 1.
BAL-001-2 - Background Document
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Real Power Balancing Control Performance Standard Background Document
A Balancing Authority reports its CPS1 value to its regional entity each month. This monthly
value provides trending data to the Balancing Authority, NERC resources subcommittee, and
others as needed to detect changes that may indicate poor control on behalf of the Balancing
Authority. Requirement R1 remains unchanged, although the wording of the requirement was
modified to provide clarity
Additionally, the drafting team added Regulating Reserve Sharing Group as a Responsible
Entity, allowing Balancing Authorities to form Regulating Reserve Sharing Groups. This allows
the Regulating Reserve Sharing Group to meet compliance as a group for CPS1. The drafting
team also added the defined term Reserve Sharing Reporting ACE to facilitate Regulating
Reserve Sharing Groups demonstration of compliance. This facilitates the consolidation of
Balancing Authorities Areas for BAL-001 through contractual arrangements forming a virtual
Balancing Authority Area while allowing each individual entity to maintain their political
boundaries.
Requirement 2
R2. Each Balancing Authority shall operate such that its clock-minute average of Reporting
ACE does not exceed its clock-minute Balancing Authority ACE Limit (BAAL) for more
than 30 consecutive clock-minutes, calculated in accordance with Attachment 2, for the
applicable Interconnection in which the Balancing Authority operates.
Background and Rationale
Requirement R2 is a new requirement intended to replace existing BAL-001-0.1a Requirement
R2, commonly referred to as Control Performance Standard 2 (CPS2). The proposed
Requirement R2 is intended to enhance the reliability of each Interconnection by maintaining
frequency within predefined limits under all conditions.
The Balancing Authority ACE Limits (BAAL) are unique for each Balancing Authority and provide
dynamic limits for its Area Control Error (ACE) value limit as a function of its Interconnection
frequency. BAAL was derived based on reliability studies and analysis which defined a
Frequency Trigger Limit (FTL) bound measured in Hz. The FTL is equal to Scheduled Frequency,
plus or minus three times an Interconnection’s Epsilon 1 value. Epsilon 1 is the root mean
square (RMS) targeted frequency error for each Interconnection, as recommended by the NERC
Resources Subcommittee and approved by the NERC Operating Committee. Epsilon 1 values
for each Interconnection are unique. When a Balancing Authority exceeds its BAAL, it is
providing more than its share of risk that the Interconnection will exceed its FTL. When all
Balancing Authorities are within their BAAL (high and low), the Interconnection frequency will
be within its FTL limits.
BAAL is defined by two equations; BAAL low and BAAL high. BAAL low is for Interconnection
frequency values less than Scheduled Frequency, and BAAL high is for Interconnection
frequency values greater than Scheduled Frequency. BAAL values for each Balancing Authority
BAL-001-2 - Background Document
July, 2013

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Real Power Balancing Control Performance Standard Background Document
are dynamic and change as Interconnection frequency changes. For example, as
Interconnection frequency moves from Scheduled Frequency, the ACE limit for each Balancing
Authority becomes more restrictive. The BAAL provides each Balancing Authority a dynamic
ACE limit that is a function of Interconnection frequency.
CPS2 was not designed to address Interconnection frequency. Currently, it measures the ability
of a Balancing Authority to maintain its average ACE within a fixed limit of plus or minus a MW
value called L10. To be compliant, a Balancing Authority must demonstrate its average ACE
value during a consecutive 10-minute period was within the L10 bound 90 percent of all 10minute periods over a one-month period. While this standard does require the Balancing
Authority to correct its ACE to not exceed specific bounds, it fails to recognize Interconnection
frequency. For example, the Balancing Authority may be increasing or decreasing generation to
meet its CPS2 bounds, even if this is a direction that reduces reliability by moving
Interconnection frequency farther from its scheduled value. CPS2 allows a Balancing Authority
to be outside its ACE bounds 10 percent of the time. There are 72 hours per month that a
Balancing Authority’s ACE can be outside its L10 limits and be compliant with CPS2.
In summary, the proposed BAAL requirement will provide dynamic limits that are Balancing
Authority and Interconnection specific. These ACE values are based on identified
Interconnection frequency limits to ensure the Interconnection returns to a reliable state when
an individual Balancing Authority’s ACE or Interconnection frequency deviates into a region that
contributes too much risk to the Interconnection. This requirement replaces and improves
upon CPS2, which is not dynamic, is not based on Interconnection frequency, and allows for a
Balancing Authority’s ACE value to be unbounded for a specific amount of time during a
calendar month.

Change From 60Hz to Scheduled Frequency
The base frequency for the determination of BAAL was changed from 60 Hz to Scheduled
Frequency, FS. This change was made to resolve a long-standing problem with the requirement
as first presented by the Balancing Resources and Demand Standard Drafting Team. The
following presents information about the reason for the initial choice of 60 Hz and the need to
change this value to Scheduled Frequency.
The initial BAAL equations were developed upon the assumption that the Frequency Trigger
Limit (FTL) should be based upon Scheduled Frequency as shown in this draft of the standard.
During initial development of values for the FTL the BRD SDT used a deterministic method for
the selection of FTL based upon the Under-Frequency Relay Limit (UFRL) of an interconnection.
Since the Under-Frequency Relay Limit of the interconnection is fixed the SDT chose to use a
fixed value of starting frequency that would maintain a fixed frequency difference between the
FTL and the UFRL. Therefore, the BRD SDT chose to base BAAL on a starting frequency of 60 Hz
BAL-001-2 - Background Document
July, 2013

6

Real Power Balancing Control Performance Standard Background Document
under the assumption that if the UFRL did not change then the FTL and base frequency should
not change. The BAAL Field Trial was started using these values.
Shortly after the field trial started, directed research supporting the selection of the FTL for the
Eastern Interconnection was completed. Unfortunately, the methods used to support the
selection of an FTL for the Eastern Interconnection could not be repeated successfully for the
other interconnections. Included in the final report was a recommendation that a multiple of 3
to 4 times the 1 for the interconnection could provide an acceptable alternative choice for
determining the FTL.1 Since the field trial had already started, no change was made to the
initial FTL for the Eastern Interconnection, but as additional interconnections joined the field
trial the FTL for these new interconnections was based on 3 times 1 for the interconnection.
This change broke the linkage between FTL and the UFRL and eliminated the justification for
using 60 Hz as the only acceptable starting frequency.
As data accumulated from the Eastern Interconnection field trial, it became apparent that Time
Error Correction (TEC) causes a detrimental reliability impact. The BAC SDT recognized this
problem and initiated actions to provide a case to eliminate TEC based on its effect on
reliability. This activity caused the RBC SDT and later the BARC SDT to defer any action on the
substitution of Schedule Frequency for 60 Hz in the BAAL Equations until the TEC issue was
resolved because the elimination of TEC would eliminate the need for change. When the ERO
decided to continue to perform TEC, that decision relieved the BARC SDT of responsibility for
the reliability impact of TEC and required the team to instead consider the impact that BAAL
could have on the effectiveness of the TEC process and any conflicts that would occur with
other standards.
Two conflicts have been identified between BAAL and other standards. The first is a conflict
between the BAAL limit and Scheduled Frequency when an interconnection is attempting to
perform TEC by adjusting the Scheduled Frequency to either 59.98 of 60.02 Hz. The second is a
conflict that results in BAAL providing an ACE limit that is more restrictive than CPS1 when an
interconnection is performing TEC. These problems can both be resolved by basing the BAAL
Limit on Scheduled Frequency instead of 60 Hz. Eight graphs follow that show the conflict
between BAAL as currently defined using 60 Hz and other standards and how the change from
60 Hz to Scheduled Frequency resolves the conflict.
The first four graphs show the conflict that is created while performing TEC. Under TEC the
BAAL limit crosses both the CPS1 = 100% line and the Scheduled Frequency Line indicating the
conflict between BAAL, CPS1 and TEC when BAAL is based on 60 Hz.

1

The initial value for FTL for the Eastern Interconnection was set at 50 mHz. Three time epsilon 1 for the Eastern
Interconnection is 54 mHz.

BAL-001-2 - Background Document
July, 2013

7

Real Power Balancing Control Performance Standard Background Document
The next four graphs show how this conflict is resolved by using Scheduled Frequency as the
base for BAAL. When BAAL is determined in this manner both conflicts are resolved and do not
appear with the implementation of TEC.
Finally, resolving this conflict reduces the detrimental impact that BAAL has on some smaller
BAs on the Western Interconnection during TEC.

BAAL
Based
on
60
Hz
w/o
BAAL
BAAL
BAAL
Based
Based
Based
BAAL
BAAL
BAAL
on
on
Based
Based
on
Based
Scheduled
Scheduled
Scheduled
on
on
on
60
60
60
Frequency
Hz
Frequency
Hz
Hz
Frequency
w/
w/
Summary
Slow
FastTEC
w/
w/
TEC
TEC
w/o
Slow
FastTEC
TEC
TEC
BAAL
Based
on
Scheduled
Frequency
Summary
pu ACE/Bias=BAAL@60
ACE/Bias=BAAL@60 Frequency
Hz &
& pu
pu ACE/Bias=CPS1@100%
ACE/Bias=CPS1@100%
pu
Hz
pu ACE/Bias=BAAL@Scheduled
& pu ACE/Bias=CPS1@100%

2.5
2.5

2.0
2.0

1.5
1.5

BAAL less than
ACE when
CPS1 = 100%

1.0
1.0

pu
puACE
ACE//Bias
Bias

0.5
0.5

0.0
0.0

-0.5
-0.5

BAAL @ 60.02
BAAL @
@ 60.02
60.00
BAAL
60.00
59.98
BAAL @ 60.00
CPS1=100 @
@ 60.02
60.00
CPS1=100
60.00
59.98
BAAL @ 59.98
CPS1=100
Fast
Slow
TEC
TEC @ 60.00
CPS1=100 @ 60.02
CPS1=100 @ 59.98
CPS1=100 @ 60.00
Slow TEC
CPS1=100 @ 59.98
Fast TEC
Slow TEC

-1.0
-1.0

BAAL less than
ACE when
CPS1 = 100%

-1.5
-1.5

-2.0
-2.0

Fast TEC

59.700
59.700
59.710
59.710
59.720
59.720
59.730
59.730
59.740
59.740
59.750
59.750
59.760
59.760
59.770
59.770
59.780
59.780
59.790
59.790
59.800
59.800
59.810
59.810
59.820
59.820
59.830
59.830
59.840
59.840
59.850
59.850
59.860
59.860
59.870
59.870
59.880
59.880
59.890
59.890
59.900
59.900
59.910
59.910
59.920
59.920
59.930
59.930
59.940
59.940
59.950
59.950
59.960
59.960
59.970
59.970
59.980
59.980
59.990
59.990
60.000
60.000
60.010
60.010
60.020
60.020
60.030
60.030
60.040
60.040
60.050
60.050
60.060
60.060
60.070
60.070
60.080
60.080
60.090
60.090
60.100
60.100
60.110
60.110
60.120
60.120
60.130
60.130
60.140
60.140
60.150
60.150
60.160
60.160
60.170
60.170
60.180
60.180
60.190
60.190
60.200
60.200
60.210
60.210
60.220
60.220
60.230
60.230
60.240
60.240
60.250
60.250
60.260
60.260
60.270
60.270
60.280
60.280
60.290
60.290
60.300
60.300

-2.5
-2.5
BAL-001-2 - Background
Document
July, 2013

Frequency (Hz)
(Hz)
Frequency

Figure
Figure
Figure
Figure
7.Figure
5.
Figure
8.
6.
Figure
BAAL
BAAL
BAAL
BAAL
4.
1.3.
Based
BAAL
Based
BAAL
Based
Based
BAAL
on
oBased
Based
on
on
Scheduled
Based
Scheduled
Scheduled
Scheduled
on
onon
60
6060
Frequency
Hz
Frequency
Hz
Hz
Frequency
Frequency
w/
w/Summary
Slow
Fast
w/
w/
TEC
Summary
w/o
Fast
Slow
TEC
TEC
TEC
Figure
2.
BAAL
Based
on
60
Hz
w/o
TEC

8

BAL-001-2 – Real Power
Balancing Control
Performance Standard
Background Document
July 2013

3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Table of Contents

Table of Contents
Table of Contents ............................................................................................................................ 2
Introduction .................................................................................................................................... 3
Background and Rationale by Requirement ................................................................................... 4
Requirement 1 ............................................................................................................................ 4
Requirement 2 ............................................................................................................................ 5

BAL-001-2 - Background Document
July, 2013

2

Real Power Balancing Control Performance Standard Background Document

Introduction
This document provides background on the development, testing, and implementation of BAL001-2 - Real Power Balancing Control Standard. The intent is to explain the rationale and
considerations for the requirements and their associated compliance information.
The original work for this standard was done by the Balancing Authority Controls standard
drafting team, which later joined with the Reliability-based Control Standard drafting team.
These combined teams were renamed Balance Authority Reliability-based Control standard
drafting team (BARC SDT).
The purpose of proposed Standard BAL-001-2 is to maintain Interconnection frequency within
predefined frequency limits. This draft standard defines Balancing Authority ACE Limit (BAAL),
and required the Balancing Authority (BA) to balance its resources and demand in Real-time so
that its clock-minute average of its Area Control Error (ACE) does not exceed its BAAL for more
than 30 consecutive clock-minutes.
As a proof of concept for the proposed BAAL standard, a BAAL field trial was approved by the
NERC Standards Committee and the Operating Committee. Currently participating in the field
trial are 13 Balancing Authorities in the Eastern Interconnection, 26 Balancing Authorities in the
Western Interconnection, the ERCOT Balancing Authority, and Quebec. Reliability Coordinators
for all Interconnections continue to monitor the performance of those participating Balancing
Authorities and provide information to support monthly analysis of the BAAL field trial. As of
the end of September 2011, no reliability issues with the BAAL field trial have been identified by
any Reliability Coordinator. The Western Interconnection has experienced changes during the
field trial with potential degradation to transmission; however, no explicit linkage has been
determined between the field trial and these degradations. For further information on the
results of the Western Interconnection, please refer to the WECC Reliability-based Control Field
Trial Report.
Historical Significance
A1-A2 Control Performance Policy was implemented in 1973 as:
A1 required the Balancing Authority’s ACE to return to zero within 10 minutes of previous
zero.
A2 required that the Balancing Authority’s averaged ACE for each 10-minute period must be
within limits.
A1-A2 had three main short comings:
ƒ Lack of theoretical justification
ƒ Large ACE treated the same as a small ACE, regardless of direction
ƒ Independent of Interconnection frequency
In 1996, a new NERC policy was approved which used CPS1, CPS2, and DCS.
CPS1is a:
BAL-001-2 - Background Document
July, 2013

3

Real Power Balancing Control Performance Standard Background Document
Statistical measure of ACE variability
Measure of ACE in combination with the Interconnection’s frequency error
Based on an equation derived from frequency-based statistical theory
CPS2 is:
Designed to limit a Control Area’s (now known as a Balancing Authority)
unscheduled power flows
Similar to the old A2 criteria
The proposed BAL-001-2 retains CPS1, but proposes a new measure BAAL to replace CPS2.
Currently CPS2:
Does not have a frequency component.
CPS2 many times give the Balancing Authority the indication to move their ACE
opposite to what will help frequency.
Only requires Balancing Authorities to comply 90 percent of the time as a minimum.

Background and Rationale by Requirement
Requirement 1
R1. The Responsible Entity shall operate such that the Control Performance Standard 1
(CPS1), calculated in accordance with Attachment 1, is greater than or equal to 100
percent for the applicable Interconnection in which it operates for each preceding 12
consecutive calendar- month period, evaluated monthly.
Background and Rationale
Requirement R1 is not a new requirement. It is a restatement of the current BAL-001-0.1a
Requirement R1 with its equation and explanation of its individual components moved to an
attachment, Attachment 1 - Equations Supporting Requirement R1 and Measure M1. This
requirement is commonly referred to as Control Performance Standard 1 (CPS1). R1 is intended
to measure how well a Balancing Authority is able to control its generation and load
management programs, as measured by its Area Control Error (ACE), to support its
Interconnection’s frequency over a rolling one-year period.
CPS1 is a measure of a Balancing Authority’s control performance as it relates to its generation,
Load management, and Interconnection frequency when measured in one-minute averages
over a rolling one-year period. If all Balancing Authorities on an Interconnection are compliant
with the CPS1 measure, then the Interconnection will have a root mean square (RMS)
frequency error less than the Interconnection’s Epsilon 1.
BAL-001-2 - Background Document
July, 2013

4

Real Power Balancing Control Performance Standard Background Document
A Balancing Authority reports its CPS1 value to its regional entity each month. This monthly
value provides trending data to the Balancing Authority, NERC resources subcommittee, and
others as needed to detect changes that may indicate poor control on behalf of the Balancing
Authority. Requirement R1 remains unchanged, although the wording of the requirement was
modified to provide clarity
Additionally, the drafting team added Regulating Reserve Sharing Group as a Responsible
Entity, allowing Balancing Authorities to form Regulating Reserve Sharing Groups. This allows
the Regulating Reserve Sharing Group to meet compliance as a group for CPS1. The drafting
team also added the defined term Reserve Sharing Reporting ACE to facilitate Regulating
Reserve Sharing Groups demonstration of compliance. This facilitates the consolidation of
Balancing Authorities Areas for BAL-001 through contractual arrangements forming a virtual
Balancing Authority Area while allowing each individual entity to maintain their political
boundaries.
Requirement 2
R2. Each Balancing Authority shall operate such that its clock-minute average of Reporting
ACE does not exceed its clock-minute Balancing Authority ACE Limit (BAAL) for more
than 30 consecutive clock-minutes, as calculated in accordance with Attachment 2, for
the applicable Interconnection in which the Balancing Authority operates.
Background and Rationale
Requirement R2 is a new requirement intended to replace existing BAL-001-0.1a Requirement
R2, commonly referred to as Control Performance Standard 2 (CPS2). The proposed
Requirement R2 is intended to enhance the reliability of each Interconnection by maintaining
frequency within predefined limits under all conditions.
The Balancing Authority ACE Limits (BAAL) are unique for each Balancing Authority and provide
dynamic limits for its Area Control Error (ACE) value limit as a function of its Interconnection
frequency. BAAL was derived based on reliability studies and analysis which defined a
Frequency Trigger Limit (FTL) bound measured in Hz. The FTL is equal to Scheduled Frequency,
plus or minus three times an Interconnection’s Epsilon 1 value. Epsilon 1 is the root mean
square (RMS) targeted frequency error for each Interconnection, as recommended by the NERC
Resources Subcommittee and approved by the NERC Operating Committee. Epsilon 1 values
for each Interconnection are unique. When a Balancing Authority exceeds its BAAL, it is
providing more than its share of risk that the Interconnection will exceed its FTL. When all
Balancing Authorities are within their BAAL (high and low), the Interconnection frequency will
be within its FTL limits.
BAAL is defined by two equations; BAAL low and BAAL high. BAAL low is for Interconnection
frequency values less than Scheduled Frequency, and BAAL high is for Interconnection
frequency values greater than Scheduled Frequency. BAAL values for each Balancing Authority
BAL-001-2 - Background Document
July, 2013

5

Real Power Balancing Control Performance Standard Background Document
are dynamic and change as Interconnection frequency changes. For example, as
Interconnection frequency moves from Scheduled Frequency, the ACE limit for each Balancing
Authority becomes more restrictive. The BAAL provides each Balancing Authority a dynamic
ACE limit that is a function of Interconnection frequency.
CPS2 was not designed to address Interconnection frequency. Currently, it measures the ability
of a Balancing Authority to maintain its average ACE within a fixed limit of plus or minus a MW
value called L10. To be compliant, a Balancing Authority must demonstrate its average ACE
value during a consecutive 10-minute period was within the L10 bound 90 percent of all 10minute periods over a one-month period. While this standard does require the Balancing
Authority to correct its ACE to not exceed specific bounds, it fails to recognize Interconnection
frequency. For example, the Balancing Authority may be increasing or decreasing generation to
meet its CPS2 bounds, even if this is a direction that reduces reliability by moving
Interconnection frequency farther from its scheduled value. CPS2 allows a Balancing Authority
to be outside its ACE bounds 10 percent of the time. There are 72 hours per month that a
Balancing Authority’s ACE can be outside its L10 limits and be compliant with CPS2.
In summary, the proposed BAAL requirement will provide dynamic limits that are Balancing
Authority and Interconnection specific. These ACE values are based on identified
Interconnection frequency limits to ensure the Interconnection returns to a reliable state when
an individual Balancing Authority’s ACE or Interconnection frequency deviates into a region that
contributes too much risk to the Interconnection. This requirement replaces and improves
upon CPS2, which is not dynamic, is not based on Interconnection frequency, and allows for a
Balancing Authority’s ACE value to be unbounded for a specific amount of time during a
calendar month.

Change From 60Hz to Scheduled Frequency
The base frequency for the determination of BAAL was changed from 60 Hz to Scheduled
Frequency, FS. This change was made to resolve a long-standing problem with the requirement
as first presented by the Balancing Resources and Demand Standard Drafting Team. The
following presents information about the reason for the initial choice of 60 Hz and the need to
change this value to Scheduled Frequency.
The initial BAAL equations were developed upon the assumption that the Frequency Trigger
Limit (FTL) should be based upon Scheduled Frequency as shown in this draft of the standard.
During initial development of values for the FTL the BRD SDT used a deterministic method for
the selection of FTL based upon the Under-Frequency Relay Limit (UFRL) of an interconnection.
Since the Under-Frequency Relay Limit of the interconnection is fixed the SDT chose to use a
fixed value of starting frequency that would maintain a fixed frequency difference between the
FTL and the UFRL. Therefore, the BRD SDT chose to base BAAL on a starting frequency of 60 Hz
BAL-001-2 - Background Document
July, 2013

6

Real Power Balancing Control Performance Standard Background Document
under the assumption that if the UFRL did not change then the FTL and base frequency should
not change. The BAAL Field Trial was started using these values.
Shortly after the field trial started, directed research supporting the selection of the FTL for the
Eastern Interconnection was completed. Unfortunately, the methods used to support the
selection of an FTL for the Eastern Interconnection could not be repeated successfully for the
other interconnections. Included in the final report was a recommendation that a multiple of 3
to 4 times the 1 for the interconnection could provide an acceptable alternative choice for
determining the FTL.1 Since the field trial had already started, no change was made to the
initial FTL for the Eastern Interconnection, but as additional interconnections joined the field
trial the FTL for these new interconnections was based on 3 times 1 for the interconnection.
This change broke the linkage between FTL and the UFRL and eliminated the justification for
using 60 Hz as the only acceptable starting frequency.
As data accumulated from the Eastern Interconnection field trial, it became apparent that Time
Error Correction (TEC) causes a detrimental reliability impact. The BAC SDT recognized this
problem and initiated actions to provide a case to eliminate TEC based on its effect on
reliability. This activity caused the RBC SDT and later the BARC SDT to defer any action on the
substitution of Schedule Frequency for 60 Hz in the BAAL Equations until the TEC issue was
resolved because the elimination of TEC would eliminate the need for change. When the ERO
decided to continue to perform TEC, that decision relieved the BARC SDT of responsibility for
the reliability impact of TEC and required the team to instead consider the impact that BAAL
could have on the effectiveness of the TEC process and any conflicts that would occur with
other standards.
Two conflicts have been identified between BAAL and other standards. The first is a conflict
between the BAAL limit and Scheduled Frequency when an interconnection is attempting to
perform TEC by adjusting the Scheduled Frequency to either 59.98 of 60.02 Hz. The second is a
conflict that results in BAAL providing an ACE limit that is more restrictive thant CPS1 when an
interconnection is performing TEC. These problems can both be resolved by basing the BAAL
Limit on Scheduled Frequency instead of 60 Hz. Eight graphs follow that show the conflict
between BAAL as currently defined using 60 Hz and other standards and how the change from
60 Hz to Scheduled Frequency resolves the conflict.
The first four graphs show the conflict that is created while performing TEC. Under TEC the
BAAL limit crosses both the CPS1 = 100% line and the Scheduled Frequency Line indicating the
conflict between BAAL, CPS1 and TEC when BAAL is based on 60 Hz.

1

The initial value for FTL for the Eastern Interconnection was set at 50 mHz. Three time epsilon 1 for the Eastern
Interconnection is 54 mHz.

BAL-001-2 - Background Document
July, 2013

7

Real Power Balancing Control Performance Standard Background Document
The next four graphs show how this conflict is resolved by using Scheduled Frequency as the
base for BAAL. When BAAL is determined in this manner both conflicts are resolved and do not
appear with the implementation of TEC.
Finally, resolving this conflict reduces the detrimental impact that BAAL has on some smaller
BAs on the Western Interconnection during TEC.

BAAL
Based
on
60
Hz
w/o
BAAL
BAAL
BAAL
Based
Based
Based
BAAL
BAAL
BAAL
on
on
Based
Based
on
Based
Scheduled
Scheduled
Scheduled
on
on
on
60
60
60
Frequency
Hz
Frequency
Hz
Hz
Frequency
w/
w/
Summary
Slow
FastTEC
w/
w/
TEC
TEC
w/o
Slow
FastTEC
TEC
TEC
BAAL
Based
on
Scheduled
Frequency
Summary
pu ACE/Bias=BAAL@60
ACE/Bias=BAAL@60 Frequency
Hz &
& pu
pu ACE/Bias=CPS1@100%
ACE/Bias=CPS1@100%
pu
Hz
pu ACE/Bias=BAAL@Scheduled
& pu ACE/Bias=CPS1@100%

2.5
2.5

2.0
2.0

1.5
1.5

BAAL less than
ACE when
CPS1 = 100%

1.0
1.0

pu
puACE
ACE//Bias
Bias

0.5
0.5

0.0
0.0

-0.5
-0.5

BAAL @ 60.02
BAAL @
@ 60.02
60.00
BAAL
60.00
59.98
BAAL @ 60.00
CPS1=100 @
@ 60.02
60.00
CPS1=100
60.00
59.98
BAAL @ 59.98
CPS1=100
Fast
Slow
TEC
TEC @ 60.00
CPS1=100 @ 60.02
CPS1=100 @ 59.98
CPS1=100 @ 60.00
Slow TEC
CPS1=100 @ 59.98
Fast TEC
Slow TEC

-1.0
-1.0

BAAL less than
ACE when
CPS1 = 100%

-1.5
-1.5

-2.0
-2.0

Fast TEC

59.700
59.700
59.710
59.710
59.720
59.720
59.730
59.730
59.740
59.740
59.750
59.750
59.760
59.760
59.770
59.770
59.780
59.780
59.790
59.790
59.800
59.800
59.810
59.810
59.820
59.820
59.830
59.830
59.840
59.840
59.850
59.850
59.860
59.860
59.870
59.870
59.880
59.880
59.890
59.890
59.900
59.900
59.910
59.910
59.920
59.920
59.930
59.930
59.940
59.940
59.950
59.950
59.960
59.960
59.970
59.970
59.980
59.980
59.990
59.990
60.000
60.000
60.010
60.010
60.020
60.020
60.030
60.030
60.040
60.040
60.050
60.050
60.060
60.060
60.070
60.070
60.080
60.080
60.090
60.090
60.100
60.100
60.110
60.110
60.120
60.120
60.130
60.130
60.140
60.140
60.150
60.150
60.160
60.160
60.170
60.170
60.180
60.180
60.190
60.190
60.200
60.200
60.210
60.210
60.220
60.220
60.230
60.230
60.240
60.240
60.250
60.250
60.260
60.260
60.270
60.270
60.280
60.280
60.290
60.290
60.300
60.300

-2.5
-2.5
BAL-001-2 - Background
Document
July, 2013

Frequency (Hz)
(Hz)
Frequency

Figure
Figure
Figure
Figure
7.Figure
5.
Figure
8.
6.
Figure
BAAL
BAAL
BAAL
BAAL
4.
1.3.
Based
BAAL
Based
BAAL
Based
Based
BAAL
on
oBased
Based
on
on
Scheduled
Based
Scheduled
Scheduled
Scheduled
on
onon
60
6060
Frequency
Hz
Frequency
Hz
Hz
Frequency
Frequency
w/
w/Summary
Slow
Fast
w/
w/
TEC
TEC
Summary
w/o
Fast
Slow
TEC
TEC
TEC
Figure
2.
BAAL
Based
on
60
Hz
w/o
TEC

8

Violation Risk Factor and Violation Severity
Level Assignments
Project 2010-14.1 Balancing Authority Reliability-based Controls
- Reserves
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-001-2, Real Power Balancing Control
Performance. 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-001-2 Real Power Balancing Control Performance
VRF and VSL Assignments – February, 2013

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
2
severely affect the reliability of the Bulk Power System:
Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
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-001-2 Real Power Balancing Control Performance
VRF and VSL Assignments – February, 2013

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-001-2:

There are two requirements in BAL-001-2. Both requirements were assigned a “Medium” VRF.
VRF for BAL-001-2, Requirement R1:

•

FERC Guideline 2 — Consistency within a reliability standard exists. The requirement does not
contain sub-requirements. Both requirements in BAL-001-2 are assigned a “Medium” VRF.
Requirement R1 is similar in scope to Requirement R2.

•

FERC Guideline 3 — Consistency among reliability standards exists. This requirement is similar
in concept to the current enforceable BAL-001-0.1a Standard Requirements R1 and R2, which
have 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
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-001-2 Real Power Balancing Control Performance
VRF and VSL Assignments – February, 2013

3

VRF for BAL-001-2, Requirement R2:

•

FERC Guideline 2 — Consistency within a reliability standard exists. The requirement does not
contain subrequirements. Both requirements in BAL-001-2 are assigned a “Medium” VRF.
Requirement R2 is similar in scope to Requirement R1.

•

FERC Guideline 3 — Consistency among Reliability Standards exists. This requirement is similar
in concept to the current enforceable BAL-001-0.1a standard Requirements R1 and R2, which
have 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
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-001-2 Real Power Balancing Control Performance
VRF and VSL Assignments – February, 2013

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

High

Severe

Missing a minor
element (or a small
percentage) of the
required performance.
The performance or
product measured has
significant value, as it
almost meets the full
intent of the
requirement.

Missing at least one
significant element (or
a moderate
percentage) of the
required performance.
The performance or
product measured still
has significant value in
meeting the intent of
the requirement.

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-001-2 meet the FERC Guidelines for assessing VSLs:

BAL-001-2 Real Power Balancing Control Performance
VRF and VSL Assignments – February, 2013

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 perviolation-per-day basis is the “default” for penalty calculations.

BAL-001-2 Real Power Balancing Control Performance
VRF and VSL Assignments – February, 2013

6

The NERC VSL
Guidelines are
satisfied by
incorporating
percentage of
noncompliance
performance for
the calculated
CPS1.

As drafted, the
proposed VSLs do not
lower the current level
of compliance.

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

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 percentage of
intervals the entity is
noncompliant.

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

BAL-001-2 Real Power Balancing Control Performance
VRF and VSL Assignments – February, 2013

R1

R#

Compliance with
NERC VSL
Guidelines

VSLs for BAL-001-2 Requirement R1:

Proposed VSLs do not
expand on what is
required in the
requirement. The VSLs
assigned only consider
results of the calculation
required. Proposed VSLs
are consistent with the
requirement.

Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement

Guideline 3

7

Proposed VSLs are
based on single
violations and not a
cumulative violation
methodology.

Violation Severity Level
Assignment Should Be
Based on A Single
Violation, Not on A
Cumulative Number of
Violations

Guideline 4

The NERC VSL
Guidelines are
satisfied by
incorporating
percentage of
noncompliance
performance
for the
calculated
BAAL.

This is a new requirement.
As drafted, the proposed
VSLs do not lower the
current level of compliance.

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

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
percentage of time the
entity is noncompliant.

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

BAL-001-2 Real Power Balancing Control Performance
VRF and VSL Assignments – February, 2013

R2.

R#

Compliance with
NERC VSL
Guidelines

VSLs for BAL-001-2 Requirement R2:

Proposed VSLs do not
expand on what is
required in the
requirement. The VSLs
assigned only consider
results of the calculation
required. Proposed VSLs
are consistent with the
requirement.

Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement

Guideline 3

8

Proposed VSLs are
based on single
violations and not a
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 2010-14.1 Balancing Authority Reliability-based Controls
- Reserves
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-001-2, Real Power Balancing Control
Performance. 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 Bbulk Eelectric Ssystem instability,
separation, or a cascading sequence of failures, or could place the Bbulk Eelectric Ssystem 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 Bbulk Eelectric Ssystem, 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-001-2 Real Power Balancing Control Performance
VRF and VSL Assignments – February, 2013

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
2
severely affect the reliability of the Bulk Power System:
Emergency operations
Vegetation management
Operator personnel training
Protection systems and their coordination
Operating tools and backup facilities
Reactive power and voltage control
System modeling and data exchange
Communication protocol and facilities
Requirements to determine equipment ratings
Synchronized data recorders
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-001-2 Real Power Balancing Control Performance
VRF and VSL Assignments – February, 2013

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-001-2:

There are two requirements in BAL-001-2. Both requirements were assigned a “Medium” VRF.
VRF for BAL-001-2, Requirement R1:

•

FERC Guideline 2 — Consistency within a reliability standard exists. The requirement does not
contain sub-requirements. Both requirements in BAL-001-2 are assigned a “Medium” VRF.
Requirement R1 is similar in scope to Requirement R2.

•

FERC Guideline 3 — Consistency among reliability standards exists. This requirement is similar
in concept to the current enforceable BAL-001-0.1a Standard Requirements R1 and R2, which
have 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
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-001-2 Real Power Balancing Control Performance
VRF and VSL Assignments – February, 2013

3

VRF for BAL-001-2, Requirement R2:

•

FERC Guideline 2 — Consistency within a reliability standard exists. The requirement does not
contain subrequirements. Both requirements in BAL-001-2 are assigned a “Medium” VRF.
Requirement R2 is similar in scope to Requirement R1.

•

FERC Guideline 3 — Consistency among Reliability Standards exists. This requirement is similar
in concept to the current enforceable BAL-001-0.1a standard Requirements R1 and R2, which
have 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
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-001-2 Real Power Balancing Control Performance
VRF and VSL Assignments – February, 2013

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

High

Severe

Missing a minor
element (or a small
percentage) of the
required performance.
The performance or
product measured has
significant value, as it
almost meets the full
intent of the
requirement.

Missing at least one
significant element (or
a moderate
percentage) of the
required performance.
The performance or
product measured still
has significant value in
meeting the intent of
the requirement.

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-001-2 meet the FERC Guidelines for assessing VSLs:

BAL-001-2 Real Power Balancing Control Performance
VRF and VSL Assignments – February, 2013

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 perviolation-per-day basis is the “default” for penalty calculations.

BAL-001-2 Real Power Balancing Control Performance
VRF and VSL Assignments – February, 2013

6

The NERC VSL
Guidelines are
satisfied by
incorporating
percentage of
noncompliance
performance for
the calculated
CPS1.

As drafted, the
proposed VSLs do not
lower the current level
of compliance.

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

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 percentage of
intervals the entity is
noncompliant.

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

BAL-001-2 Real Power Balancing Control Performance
VRF and VSL Assignments – February, 2013

R1

R#

Compliance with
NERC VSL
Guidelines

VSLs for BAL-001-2 Requirement R1:

Proposed VSLs do not
expand on what is
required in the
requirement. The VSLs
assigned only consider
results of the calculation
required. Proposed VSLs
are consistent with the
requirement.

Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement

Guideline 3

7

Proposed VSLs are
based on single
violations and not a
cumulative violation
methodology.

Violation Severity Level
Assignment Should Be
Based on A Single
Violation, Not on A
Cumulative Number of
Violations

Guideline 4

The NERC VSL
Guidelines are
satisfied by
incorporating
percentage of
noncompliance
performance
for the
calculated
BAAL.

This is a new requirement.
As drafted, the proposed
VSLs do not lower the
current level of compliance.

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

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
percentage of time the
entity is noncompliant.

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

BAL-001-2 Real Power Balancing Control Performance
VRF and VSL Assignments – February, 2013

R2.

R#

Compliance with
NERC VSL
Guidelines

VSLs for BAL-001-2 Requirement R2:

Proposed VSLs do not
expand on what is
required in the
requirement. The VSLs
assigned only consider
results of the calculation
required. Proposed VSLs
are consistent with the
requirement.

Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement

Guideline 3

8

Proposed VSLs are
based on single
violations and not a
cumulative
violation
methodology.

Violation Severity
Level Assignment
Should Be Based on
A Single Violation,
Not on A Cumulative
Number of Violations

Guideline 4

BAL-001-0.1a Mapping to Proposed NERC Reliability Standard BAL-001-2
Standard BAL-001-0.1a
Comment
Proposed Standard BAL-001-2
NERC Board Approved
R1. Each Balancing Authority shall
This Requirement has been
Requirement R1
operate such that, on a rolling 12moved into BAL-001-2
The Responsible Entity shall operate such that the Control
month basis, the average of the
Requirement R1
Performance Standard 1 (CPS1), calculated in accordance with
clock-minute averages of the
Attachment 1, is greater than or equal to 100% for the
Balancing Authority’s Area Control
applicable Interconnection in which it operates for each
Error (ACE) divided by 10B (B is the
preceding 12 consecutive calendar month period, evaluated
clock-minute average of the
monthly.
Balancing Authority Area’s
Frequency Bias) times the
corresponding clock-minute
The calculation equation for CPS1 has been moved to Attachment
averages of the Interconnection’s
1 of BAL-001-2.
Frequency Error is less than a
specific limit. This limit ε12 is a
constant derived from a targeted
frequency bound (separately
calculated for each

Project 2010-14.1 Balancing Authority Reliability-based
Controls - Reserves
BAL-001-2 Real Power Balancing Control Performance
Mapping Document

BAL-001-2 Real Power Balancing Control Performance
February, 2013

The equation for ACE is:
ACE = (NIA - NIS) - 10B (FA - FS) - IME
where:
NIA is the algebraic sum of
actual flows on all tie lines.
NIS is the algebraic sum of
scheduled flows on all tie
lines.
B is the Frequency Bias
Setting (MW/0.1 Hz) for the
Balancing Authority. The
constant factor 10 converts
the frequency setting to
MW/Hz.
FA is the actual frequency.
FS is the scheduled
frequency. FS is normally 60

BAL-001-0.1a Mapping to Proposed NERC Reliability Standard BAL-001-2
Standard BAL-001-0.1a
Comment
Proposed Standard BAL-001-2
NERC Board Approved
Interconnection) that is reviewed
and set as necessary by the NERC
Operating Committee.
AVGPeriod
-10B

2

BAL-001-2 Real Power Balancing Control Performance
February, 2013

3

BAL-001-0.1a Mapping to Proposed NERC Reliability Standard BAL-001-2
Standard BAL-001-0.1a
Comment
Proposed Standard BAL-001-2
NERC Board Approved
Hz but may be offset to
effect manual time error
corrections.
IME is the meter error
correction factor typically
estimated from the
difference between the
integrated hourly average
of the net tie line flows
(NIA) and the hourly net
interchange demand
measurement (megawatthour). This term should
normally be very small or
zero.
R2. Each Balancing Authority shall
Requirement R2
This Requirement has been
operate such that its average ACE
removed from BAL-001-2 and
Each Balancing Authority shall operate such that its clockfor at least 90% of clock-tenreplaced with the proposed
minute average of Reporting ACE does not exceed its
minute periods (6 non-overlapping Requirement R2 for BAAL.
clock-minute Balancing Authority ACE Limit (BAAL) for
periods per hour) during a calendar
more than 30 consecutive clock-minutes, calculated in
month is within a specific limit,
accordance with Attachment 2, for the applicable
referred to as L10.
Interconnection in which the Balancing Authority
AVG10-minute (ACEi ) ≤ L10
operates.
where:

BAL-001-2 Real Power Balancing Control Performance
February, 2013

R3. Each Balancing Authority providing
Overlap Regulation Service shall

This Requirement has been
moved into the BAL-001-2

4

Attachment 1
A Balancing Authority providing Overlap Regulation Service

BAL-001-0.1a Mapping to Proposed NERC Reliability Standard BAL-001-2
Standard BAL-001-0.1a
Comment
Proposed Standard BAL-001-2
NERC Board Approved
L10=1.65 Є10
ε10 is a constant derived from the
The calculation equation for BAAL is located in Attachment 2 of
targeted frequency bound. It
BAL-001-2.
is the targeted root-meansquare (RMS) value of tenminute average Frequency
Error based on frequency
performance over a given
year. The bound, ε10, is the
same for every Balancing
Authority Area within an
Interconnection, and Bs is the
sum of the Frequency Bias
Settings of the Balancing
Authority Areas in the
respective Interconnection.
For Balancing Authority Areas
with variable bias, this is
equal to the sum of the
minimum Frequency Bias
Settings.

Any Balancing Authority receiving
Overlap Regulation Service shall
not have its control performance
evaluated (i.e. from a control
performance perspective, the
Balancing Authority has shifted all
control requirements to the
Balancing Authority providing
Overlap Regulation Service).

BAL-001-2 Real Power Balancing Control Performance
February, 2013

R4.

This Requirement has been
moved into the BAL-001-2
Applicability Section.

5

Applicability Section 4.1.1
A Balancing Authority receiving Overlap Regulation Service is
not subject to Control Performance Standard 1 (CPS1) or
Balancing Authority ACE Limit (BAAL) compliance evaluation.

BAL-001-0.1a Mapping to Proposed NERC Reliability Standard BAL-001-2
Standard BAL-001-0.1a
Comment
Proposed Standard BAL-001-2
NERC Board Approved
evaluate Requirement R1 (i.e.,
Attachment 1.
to another Balancing Authority calculates its CPS1
Control Performance Standard 1 or
performance after combining its Reporting ACE and
CPS1) and Requirement R2 (i.e.,
Frequency Bias Settings with the Reporting ACE and
Control Performance Standard 2 or
Frequency Bias Settings of the Balancing Authority receiving
CPS2) using the characteristics of
Regulation Service.
the combined ACE and combined
Frequency Bias Settings.

BAL-001-0.1a Mapping to Proposed NERC Reliability Standard BAL-001-2
Standard BAL-001-0.1a
Comment
Proposed Standard BAL-001-2
NERC Board Approved
R1. Each Balancing Authority shall
This Requirement has been
Requirement R1
operate such that, on a rolling 12moved into BAL-001-2
The Responsible Entity shall operate such that the Control
month basis, the average of the
Requirement R1
Performance Standard 1 (CPS1), calculated in accordance with
clock-minute averages of the
Attachment 1, is greater than or equal to 100% for the
Balancing Authority’s Area Control
applicable Interconnection in which it operates for each
Error (ACE) divided by 10B (B is the
preceding 12 consecutive calendar month period, evaluated
clock-minute average of the
monthly.
Balancing Authority Area’s
Frequency Bias) times the
corresponding clock-minute
The calculation equation for CPS1 has been moved to Attachment
averages of the Interconnection’s
1 of BAL-001-2.
Frequency Error is less than a
specific limit. This limit ε12 is a
constant derived from a targeted
frequency bound (separately
calculated for each

Project 2010-14.1 Balancing Authority Reliability-based
Controls - Reserves
BAL-001-2 Real Power Balancing Control Performance
Mapping Document

BAL-001-2 Real Power Balancing Control Performance
February, 2013

The equation for ACE is:
ACE = (NIA - NIS) - 10B (FA - FS) - IME
where:
NIA is the algebraic sum of
actual flows on all tie lines.
NIS is the algebraic sum of
scheduled flows on all tie
lines.
B is the Frequency Bias
Setting (MW/0.1 Hz) for the
Balancing Authority. The
constant factor 10 converts
the frequency setting to
MW/Hz.
FA is the actual frequency.
FS is the scheduled
frequency. FS is normally 60

BAL-001-0.1a Mapping to Proposed NERC Reliability Standard BAL-001-2
Standard BAL-001-0.1a
Comment
Proposed Standard BAL-001-2
NERC Board Approved
Interconnection) that is reviewed
and set as necessary by the NERC
Operating Committee.
AVGPeriod
-10B

2

BAL-001-2 Real Power Balancing Control Performance
February, 2013

3

BAL-001-0.1a Mapping to Proposed NERC Reliability Standard BAL-001-2
Standard BAL-001-0.1a
Comment
Proposed Standard BAL-001-2
NERC Board Approved
Hz but may be offset to
effect manual time error
corrections.
IME is the meter error
correction factor typically
estimated from the
difference between the
integrated hourly average
of the net tie line flows
(NIA) and the hourly net
interchange demand
measurement (megawatthour). This term should
normally be very small or
zero.
R2. Each Balancing Authority shall
Requirement R2
This Requirement has been
operate such that its average ACE
removed from BAL-001-2 and
Each Balancing Authority shall operate such that its clockfor at least 90% of clock-tenreplaced with the proposed
minute average of Reporting ACE does not exceed its
minute periods (6 non-overlapping Requirement R2 for BAAL.
clock-minute Balancing Authority ACE Limit (BAAL) for
periods per hour) during a calendar
more than 30 consecutive clock-minutes, as calculated in
month is within a specific limit,
accordance with Attachment 2, for the applicable
referred to as L10.
Interconnection in which the Balancing Authority
AVG10-minute (ACEi ) ≤ L10
operates.
where:

BAL-001-2 Real Power Balancing Control Performance
February, 2013

R3. Each Balancing Authority providing
Overlap Regulation Service shall

This Requirement has been
moved into the BAL-001-2

4

Attachment 1
A Balancing Authority providing Overlap Regulation Service

BAL-001-0.1a Mapping to Proposed NERC Reliability Standard BAL-001-2
Standard BAL-001-0.1a
Comment
Proposed Standard BAL-001-2
NERC Board Approved
L10=1.65 Є10
ε10 is a constant derived from the
The calculation equation for BAAL is located in Attachment 2 of
targeted frequency bound. It
BAL-001-2.
is the targeted root-meansquare (RMS) value of tenminute average Frequency
Error based on frequency
performance over a given
year. The bound, ε10, is the
same for every Balancing
Authority Area within an
Interconnection, and Bs is the
sum of the Frequency Bias
Settings of the Balancing
Authority Areas in the
respective Interconnection.
For Balancing Authority Areas
with variable bias, this is
equal to the sum of the
minimum Frequency Bias
Settings.

Any Balancing Authority receiving
Overlap Regulation Service shall
not have its control performance
evaluated (i.e. from a control
performance perspective, the
Balancing Authority has shifted all
control requirements to the
Balancing Authority providing
Overlap Regulation Service).

BAL-001-2 Real Power Balancing Control Performance
February, 2013

R4.

This Requirement has been
moved into the BAL-001-2
Applicability Section.

5

Applicability Section 4.1.1
A Balancing Authority receiving Overlap Regulation Service is
not subject to Control Performance Standard 1 (CPS1) or
Balancing Authority ACE Limit (BAAL) compliance evaluation.

BAL-001-0.1a Mapping to Proposed NERC Reliability Standard BAL-001-2
Standard BAL-001-0.1a
Comment
Proposed Standard BAL-001-2
NERC Board Approved
evaluate Requirement R1 (i.e.,
Attachment 1.
to another Balancing Authority calculates its CPS1
Control Performance Standard 1 or
performance after combining its Reporting ACE and
CPS1) and Requirement R2 (i.e.,
Frequency Bias Settings with the Reporting ACE and
Control Performance Standard 2 or
Frequency Bias Settings of the Balancing Authority receiving
CPS2) using the characteristics of
Regulation Service.
the combined ACE and combined
Frequency Bias Settings.

Standards Announcement
Project 2010-14.1 Phase 1 of Balancing Authority
Reliability-based Controls: Reserves
BAL-001-2
Final Ballot is now open through Thursday, July 25, 2013
Now Available

A final ballot for BAL-001-2- Real Power Balancing Control Performance is now open through 8 p.m.
Eastern on Thursday, July 25, 2013.
The other standard (BAL-002-2) in this project will be posted and announced separately at a later date.
Background information for this project can be found on the project page.
Instructions
In the final ballot, votes are counted by exception. Only members of the ballot pool may cast a ballot;
all ballot pool members may change their previously cast votes. A ballot pool member who failed to
cast a ballot during the last ballot window may cast a ballot in the final ballot window. If a ballot pool
member does not participate in the final ballot, that member’s vote cast in the previous ballot will be
carried over as that member’s vote in the final ballot.
Members of the ballot pool associated with this project may log in and submit their vote for the
standard by clicking here.
Next Steps

Voting results for BAL-001-2 will be posted and announced after the ballot window closes. If approved,
the standard will be submitted to the Board of Trustees for adoption and then filed with the
appropriate regulatory authorities.
Standards Process

The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.

For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd.NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement | Project 2010-14.1 Phase 1 of Balancing Authority Reliability-based Controls: Reserves

2

Standards Announcement

Project 2010-14.1 Phase 1 of Balancing Authority Reliability-based
Controls: Reserves
BAL-001-2
Final Ballot Results
Now Available

A final ballot for BAL-001-2- Real Power Balancing Control Performance concluded at 8 p.m. Eastern
on Thursday, July 25, 2013.
Voting statistics for the final ballot are listed below, and the Ballot Results page provides a link to
the detailed results.
Approval
Quorum: 92.31%
Approval: 74.54%
Background information for this project can be found on the project page
Next Steps

The standard will be presented to the Board of Trustees for adoption and then filed with the
appropriate regulatory authorities.
Standards Process

The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd.NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

NERC Standards



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dŚŝƐƐĞĐƚŝŽŶŝƐŵĂŝŶƚĂŝŶĞĚďLJƚŚĞĚƌĂĨƚŝŶŐƚĞĂŵĚƵƌŝŶŐƚŚĞĚĞǀĞůŽƉŵĞŶƚŽĨƚŚĞƐƚĂŶĚĂƌĚĂŶĚǁŝůů
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ĞǀĞůŽƉŵĞŶƚ^ƚĞƉƐŽŵƉůĞƚĞĚ͗
ϭ͘ dŚĞ^ZĨŽƌWƌŽũĞĐƚϮϬϬϳͲϭϴ͕ZĞůŝĂďŝůŝƚLJĂƐĞĚŽŶƚƌŽůƐ͕ǁĂƐƉŽƐƚĞĚĨŽƌĂϯϬͲĚĂLJĨŽƌŵĂů
ĐŽŵŵĞŶƚƉĞƌŝŽĚŽŶDĂLJϭϱ͕ϮϬϬϳ͘
Ϯ͘ ƌĞǀŝƐĞĚ^ZĨŽƌWƌŽũĞĐƚϮϬϬϳͲϬϱ͕ZĞůŝĂďŝůŝƚLJĂƐĞĚŽŶƚƌŽůƐ͕ǁĂƐƉŽƐƚĞĚĨŽƌĂƐĞĐŽŶĚ
ϯϬͲĚĂLJĨŽƌŵĂůĐŽŵŵĞŶƚƉĞƌŝŽĚŽŶ^ĞƉƚĞŵďĞƌϭϬ͕ϮϬϬϳ͘
ϯ͘ dŚĞ^ƚĂŶĚĂƌĚƐŽŵŵŝƚƚĞĞĂƉƉƌŽǀĞĚWƌŽũĞĐƚϮϬϬϳͲϭϴ͕ZĞůŝĂďŝůŝƚLJĂƐĞĚŽŶƚƌŽůƐ͕ƚŽďĞ
ŵŽǀĞĚƚŽƐƚĂŶĚĂƌĚĚƌĂĨƚŝŶŐŽŶĞĐĞŵďĞƌϭϭ͕ϮϬϬϳ͘
ϰ͘ dŚĞ^ZĨŽƌWƌŽũĞĐƚϮϬϬϳͲϬϱ͕ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJŽŶƚƌŽůƐ͕ǁĂƐƉŽƐƚĞĚĨŽƌĂϯϬͲĚĂLJ
ĨŽƌŵĂůĐŽŵŵĞŶƚƉĞƌŝŽĚŽŶ:ƵůLJϯ͕ϮϬϬϳ͘
ϱ͘ dŚĞ^ƚĂŶĚĂƌĚƐŽŵŵŝƚƚĞĞĂƉƉƌŽǀĞĚWƌŽũĞĐƚϮϬϬϳͲϬϱ͕ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJŽŶƚƌŽůƐ͕ƚŽ
ďĞŵŽǀĞĚƚŽƐƚĂŶĚĂƌĚĚƌĂĨƚŝŶŐŽŶ:ĂŶƵĂƌLJϭϴ͕ϮϬϬϴ͘
ϲ͘ dŚĞ^ƚĂŶĚĂƌĚƐŽŵŵŝƚƚĞĞĂƉƉƌŽǀĞĚƚŚĞŵĞƌŐĞƌŽĨWƌŽũĞĐƚϮϬϬϳͲϬϱ͕ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ
ŽŶƚƌŽůƐ͕ĂŶĚWƌŽũĞĐƚϮϬϬϳͲϭϴ͕ZĞůŝĂďŝůŝƚLJͲďĂƐĞĚŽŶƚƌŽů͕ĂƐWƌŽũĞĐƚϮϬϭϬͲϭϰ͕ĂůĂŶĐŝŶŐ
ƵƚŚŽƌŝƚLJZĞůŝĂďŝůŝƚLJͲďĂƐĞĚŽŶƚƌŽůƐŽŶ:ƵůLJϮϴ͕ϮϬϭϬ͘
ϳ͘ dŚĞEZ^ƚĂŶĚĂƌĚƐŽŵŵŝƚƚĞĞĂƉƉƌŽǀĞĚďƌĞĂŬŝŶŐWƌŽũĞĐƚϮϬϭϬͲϭϰ͕ĂůĂŶĐŝŶŐ
ƵƚŚŽƌŝƚLJZĞůŝĂďŝůŝƚLJͲďĂƐĞĚŽŶƚƌŽůƐ͕ŝŶƚŽƚǁŽƉŚĂƐĞƐĂŶĚŵŽǀŝŶŐWŚĂƐĞϭ;WƌŽũĞĐƚϮϬϭϬͲ
ϭϰ͘ϭ͕ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJZĞůŝĂďŝůŝƚLJͲďĂƐĞĚŽŶƚƌŽůƐʹZĞƐĞƌǀĞƐͿŝŶƚŽĨŽƌŵĂůƐƚĂŶĚĂƌĚƐ
ĚĞǀĞůŽƉŵĞŶƚŽŶ:ƵůLJϭϯ͕ϮϬϭϭ͘
ϴ͘ dŚĞĚƌĂĨƚƐƚĂŶĚĂƌĚǁĂƐƉŽƐƚĞĚĨŽƌϯϬͲĚĂLJĨŽƌŵĂůŝŶĚƵƐƚƌLJĐŽŵŵĞŶƚƉĞƌŝŽĚĨƌŽŵ:ƵŶĞϰ͕
ϮϬϭϮƚŚƌŽƵŐŚ:ƵůLJϯ͕ϮϬϭϮ͘
ϵ͘ dŚĞĚƌĂĨƚƐƚĂŶĚĂƌĚǁĂƐƉŽƐƚĞĚĨŽƌϰϱͲĚĂLJĨŽƌŵĂůŝŶĚƵƐƚƌLJĐŽŵŵĞŶƚƉĞƌŝŽĚĂŶĚŝŶŝƚŝĂů
ďĂůůŽƚĨƌŽŵDĂƌĐŚϭϮ͕ϮϬϭϯƚŚƌŽƵŐŚƉƌŝůϮϱ͕ϮϬϭϯ͘

WƌŽƉŽƐĞĚĐƚŝŽŶWůĂŶĂŶĚĞƐĐƌŝƉƚŝŽŶŽĨƵƌƌĞŶƚƌĂĨƚ͗
dŚŝƐŝƐƚŚĞƚŚŝƌĚƉŽƐƚŝŶŐŽĨƚŚĞƉƌŽƉŽƐĞĚƐƚĂŶĚĂƌĚ͘dŚŝƐƉƌŽƉŽƐĞĚĚƌĂĨƚƐƚĂŶĚĂƌĚǁŝůůďĞƉŽƐƚĞĚ
ĨŽƌĂϰϱͲĚĂLJĨŽƌŵĂůĐŽŵŵĞŶƚƉĞƌŝŽĚĂŶĚϭϬͲĚĂLJƐƵĐĐĞƐƐŝǀĞďĂůůŽƚ͘

&ƵƚƵƌĞĞǀĞůŽƉŵĞŶƚWůĂŶ͗
ŶƚŝĐŝƉĂƚĞĚĐƚŝŽŶƐ
ϭ͘ dŚŝƌĚƉŽƐƚŝŶŐ

:ƵůLJͬƵŐƵƐƚϮϬϭϯ

Ϯ͘ ^ƵĐĐĞƐƐŝǀĞĂůůŽƚ

>ͲϬϬϮͲϮ
:ƵůLJϮϬϭϯ

ŶƚŝĐŝƉĂƚĞĚĂƚĞ

ƵŐƵƐƚϮϬϭϯ



WĂŐĞϭŽĨϭϭ



^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮʹŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ
ĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
ϯ͘ ZĞĐŝƌĐƵůĂƚŝŽŶĂůůŽƚ

KĐƚŽďĞƌϮϬϭϯ

ϰ͘ EZKdĂĚŽƉƚŝŽŶ͘

EŽǀĞŵďĞƌϮϬϭϯ




>ͲϬϬϮͲϮ
:ƵůLJϮϬϭϯ





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ĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ

ĞĨŝŶŝƚŝŽŶƐŽĨdĞƌŵƐhƐĞĚŝŶ^ƚĂŶĚĂƌĚ
dŚŝƐƐĞĐƚŝŽŶŝŶĐůƵĚĞƐĂůůŶĞǁůLJĚĞĨŝŶĞĚŽƌƌĞǀŝƐĞĚƚĞƌŵƐƵƐĞĚŝŶƚŚĞƉƌŽƉŽƐĞĚƐƚĂŶĚĂƌĚ͘dĞƌŵƐ
ĂůƌĞĂĚLJĚĞĨŝŶĞĚŝŶƚŚĞZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚƐ'ůŽƐƐĂƌLJŽĨdĞƌŵƐĂƌĞŶŽƚƌĞƉĞĂƚĞĚŚĞƌĞ͘EĞǁŽƌ
ƌĞǀŝƐĞĚĚĞĨŝŶŝƚŝŽŶƐůŝƐƚĞĚďĞůŽǁďĞĐŽŵĞĂƉƉƌŽǀĞĚǁŚĞŶƚŚĞƉƌŽƉŽƐĞĚƐƚĂŶĚĂƌĚŝƐĂƉƉƌŽǀĞĚ͘
tŚĞŶƚŚĞƐƚĂŶĚĂƌĚďĞĐŽŵĞƐĞĨĨĞĐƚŝǀĞ͕ƚŚĞƐĞĚĞĨŝŶĞĚƚĞƌŵƐǁŝůůďĞƌĞŵŽǀĞĚĨƌŽŵƚŚĞŝŶĚŝǀŝĚƵĂů
ƐƚĂŶĚĂƌĚĂŶĚĂĚĚĞĚƚŽƚŚĞ'ůŽƐƐĂƌLJ͘
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͗ŶLJƐŝŶŐůĞĞǀĞŶƚĚĞƐĐƌŝďĞĚŝŶ^ƵďƐĞĐƚŝŽŶƐ;Ϳ͕;Ϳ͕Žƌ;ͿďĞůŽǁ͕
ŽƌĂŶLJƐĞƌŝĞƐŽĨƐƵĐŚŽƚŚĞƌǁŝƐĞƐŝŶŐůĞĞǀĞŶƚƐ͕ǁŝƚŚĞĂĐŚƐĞƉĂƌĂƚĞĚĨƌŽŵƚŚĞŶĞdžƚďLJůĞƐƐƚŚĂŶ
ŽŶĞŵŝŶƵƚĞ͘
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Ă͘ ƵĞƚŽ
ŝ͘ hŶŝƚƚƌŝƉƉŝŶŐ͕
ŝŝ͘ >ŽƐƐŽĨŐĞŶĞƌĂƚŽƌ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ&ĂĐŝůŝƚLJƌĞƐƵůƚŝŶŐŝŶŝƐŽůĂƚŝŽŶŽĨƚŚĞ
ŐĞŶĞƌĂƚŽƌĨƌŽŵƚŚĞƵůŬůĞĐƚƌŝĐ^LJƐƚĞŵŽƌĨƌŽŵƚŚĞƌĞƐƉŽŶƐŝďůĞĞŶƚŝƚLJ͛Ɛ
ĞůĞĐƚƌŝĐƐLJƐƚĞŵ͕Žƌ
ŝŝŝ͘ ^ƵĚĚĞŶƵŶƉůĂŶŶĞĚŽƵƚĂŐĞŽĨƚƌĂŶƐŵŝƐƐŝŽŶ&ĂĐŝůŝƚLJ͖
ď͘ ŶĚ͕ƚŚĂƚĐĂƵƐĞƐĂŶƵŶĞdžƉĞĐƚĞĚĐŚĂŶŐĞƚŽƚŚĞƌĞƐƉŽŶƐŝďůĞĞŶƚŝƚLJ͛Ɛ͖
͘ ^ƵĚĚĞŶůŽƐƐŽĨĂŶŝŵƉŽƌƚ͕ĚƵĞƚŽĨŽƌĐĞĚŽƵƚĂŐĞŽĨƚƌĂŶƐŵŝƐƐŝŽŶĞƋƵŝƉŵĞŶƚƚŚĂƚĐĂƵƐĞƐ
ĂŶƵŶĞdžƉĞĐƚĞĚŝŵďĂůĂŶĐĞďĞƚǁĞĞŶŐĞŶĞƌĂƚŝŽŶĂŶĚůŽĂĚŽŶƚŚĞ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͘
C. ^ƵĚĚĞŶƌĞƐƚŽƌĂƚŝŽŶŽĨĂůŽĂĚƚŚĂƚǁĂƐƵƐĞĚĂƐĂƌĞƐŽƵƌĐĞƚŚĂƚĐĂƵƐĞƐĂŶƵŶĞdžƉĞĐƚĞĚ
ĐŚĂŶŐĞƚŽƚŚĞƌĞƐƉŽŶƐŝďůĞĞŶƚŝƚLJ͛Ɛ͘
DŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;D^^Ϳ͗dŚĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͕ĚƵĞƚŽĂƐŝŶŐůĞ
ĐŽŶƚŝŶŐĞŶĐLJ͕ƚŚĂƚǁŽƵůĚƌĞƐƵůƚŝŶƚŚĞŐƌĞĂƚĞƐƚůŽƐƐ;ŵĞĂƐƵƌĞĚŝŶDtͿŽĨƌĞƐŽƵƌĐĞŽƵƚƉƵƚƵƐĞĚ
ďLJƚŚĞZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ;Z^'ͿŽƌĂĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJƚŚĂƚŝƐŶŽƚƉĂƌƚŝĐŝƉĂƚŝŶŐĂƐĂ
ŵĞŵďĞƌŽĨĂZ^'ĂƚƚŚĞƚŝŵĞŽĨƚŚĞĞǀĞŶƚƚŽŵĞĞƚĨŝƌŵƐLJƐƚĞŵůŽĂĚĂŶĚĞdžƉŽƌƚŽďůŝŐĂƚŝŽŶ
;ĞdžĐůƵĚŝŶŐĞdžƉŽƌƚŽďůŝŐĂƚŝŽŶĨŽƌǁŚŝĐŚŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞŽďůŝŐĂƚŝŽŶƐĂƌĞďĞŝŶŐŵĞƚďLJƚŚĞ
ƐŝŶŬĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJͿ͘
ZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͗ŶLJĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƌĞƐƵůƚŝŶŐŝŶĂůŽƐƐ
ŽĨDtŽƵƚƉƵƚŐƌĞĂƚĞƌƚŚĂŶŽƌĞƋƵĂůƚŽƚŚĞůĞƐƐĞƌĂŵŽƵŶƚŽĨϴϬƉĞƌĐĞŶƚŽĨƚŚĞDŽƐƚ^ĞǀĞƌĞ
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ǁŝƚŚŝŶĂƌŽůůŝŶŐŽŶĞͲŵŝŶƵƚĞŝŶƚĞƌǀĂůďĂƐĞĚŽŶD^ƐĐĂŶƌĂƚĞĚĂƚĂ͘dŚĞϴϬйƚŚƌĞƐŚŽůĚŵĂLJďĞ
ƌĞĚƵĐĞĚƵƉŽŶǁƌŝƚƚĞŶŶŽƚŝĨŝĐĂƚŝŽŶƚŽƚŚĞZĞŐŝŽŶĂůŶƚŝƚLJ͘
•

ĂƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶͲϵϬϬDt

•

tĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶʹϱϬϬDt

•

ZKdʹϴϬϬDt

•

YƵĞďĞĐʹϱϬϬDt

>ͲϬϬϮͲϮ
:ƵůLJϮϬϭϯ



WĂŐĞϯŽĨϭϭ



^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮʹŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ
ĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͗ƉĞƌŝŽĚďĞŐŝŶŶŝŶŐĂƚƚŚĞƚŝŵĞƚŚĂƚƚŚĞƌĞƐŽƵƌĐĞŽƵƚƉƵƚ
ďĞŐŝŶƐƚŽĚĞĐůŝŶĞǁŝƚŚŝŶƚŚĞĨŝƌƐƚŽŶĞͲŵŝŶƵƚĞŝŶƚĞƌǀĂůƚŚĂƚĚĞĨŝŶĞƐĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJ
ǀĞŶƚ͕ĂŶĚĞdžƚĞŶĚƐĨŽƌĨŝĨƚĞĞŶŵŝŶƵƚĞƐƚŚĞƌĞĂĨƚĞƌ͘
ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚ͗ƉĞƌŝŽĚŶŽƚĞdžĐĞĞĚŝŶŐϵϬŵŝŶƵƚĞƐĨŽůůŽǁŝŶŐƚŚĞĞŶĚ
ŽĨƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͘
WƌĞͲZĞƉŽƌƚŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞ͗dŚĞĂǀĞƌĂŐĞǀĂůƵĞŽĨZĞƉŽƌƚŝŶŐ͕ŽƌZĞƐĞƌǀĞ
^ŚĂƌŝŶŐ'ƌŽƵƉZĞƉŽƌƚŝŶŐǁŚĞŶĂƉƉůŝĐĂďůĞ͕ŝŶƚŚĞϭϲƐĞĐŽŶĚŝŶƚĞƌǀĂůŝŵŵĞĚŝĂƚĞůLJƉƌŝŽƌƚŽ
ƚŚĞƐƚĂƌƚŽĨƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚďĂƐĞĚŽŶD^ƐĐĂŶƌĂƚĞĚĂƚĂ͘
ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉZĞƉŽƌƚŝŶŐ͗ƚĂŶLJŐŝǀĞŶƚŝŵĞŽĨŵĞĂƐƵƌĞŵĞŶƚĨŽƌƚŚĞĂƉƉůŝĐĂďůĞ
ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ͕ƚŚĞĂůŐĞďƌĂŝĐƐƵŵŽĨƚŚĞƐ;ŽƌĞƋƵŝǀĂůĞŶƚĂƐĐĂůĐƵůĂƚĞĚĂƚƐƵĐŚƚŝŵĞ
ŽĨŵĞĂƐƵƌĞŵĞŶƚͿŽĨƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐƉĂƌƚŝĐŝƉĂƚŝŶŐŝŶƚŚĞZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉĂƚƚŚĞ
ƚŝŵĞŽĨŵĞĂƐƵƌĞŵĞŶƚ͘

ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ͗dŚĞƉƌŽǀŝƐŝŽŶŽĨĐĂƉĂĐŝƚLJƚŚĂƚŵĂLJďĞĚĞƉůŽLJĞĚďLJƚŚĞĂůĂŶĐŝŶŐ
ƵƚŚŽƌŝƚLJƚŽƌĞƐƉŽŶĚƚŽĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚŽƚŚĞƌĐŽŶƚŝŶŐĞŶĐLJƌĞƋƵŝƌĞŵĞŶƚƐ
;ƐƵĐŚĂƐŶĞƌŐLJŵĞƌŐĞŶĐLJůĞƌƚƐ>ĞǀĞůϮŽƌ>ĞǀĞůϯĂƐƐƉĞĐŝĨŝĞĚŝŶƚŚĞĂƐƐŽĐŝĂƚĞĚKW
ƐƚĂŶĚĂƌĚͿ͘dŚĞĐĂƉĂĐŝƚLJŵĂLJďĞƉƌŽǀŝĚĞĚďLJƌĞƐŽƵƌĐĞƐƐƵĐŚĂƐĞŵĂŶĚ^ŝĚĞDĂŶĂŐĞŵĞŶƚ
;^DͿ͕/ŶƚĞƌƌƵƉƚŝďůĞ>ŽĂĚĂŶĚƵŶůŽĂĚĞĚŐĞŶĞƌĂƚŝŽŶ͘

ZĞƉŽƌƚŝŶŐ͗dŚĞƐĐĂŶƌĂƚĞǀĂůƵĞƐŽĨĂĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛ƐƌĞĂŽŶƚƌŽůƌƌŽƌ;Ϳ
ŵĞĂƐƵƌĞĚŝŶDt͕ǁŚŝĐŚŝŶĐůƵĚĞƐƚŚĞĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛ƐEĞƚĐƚƵĂů
/ŶƚĞƌĐŚĂŶŐĞĂŶĚŝƚƐEĞƚ^ĐŚĞĚƵůĞĚ/ŶƚĞƌĐŚĂŶŐĞ͕ƉůƵƐŝƚƐ&ƌĞƋƵĞŶĐLJŝĂƐŽďůŝŐĂƚŝŽŶ͕ƉůƵƐĂŶLJ
ŬŶŽǁŶŵĞƚĞƌĞƌƌŽƌ͘/ŶƚŚĞtĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͕ZĞƉŽƌƚŝŶŐŝŶĐůƵĚĞƐƵƚŽŵĂƚŝĐdŝŵĞ
ƌƌŽƌŽƌƌĞĐƚŝŽŶ;dͿ͘
ZĞƉŽƌƚŝŶŐŝƐĐĂůĐƵůĂƚĞĚĂƐĨŽůůŽǁƐ͗


ZĞƉŽƌƚŝŶŐс;E/оE/^ͿоϭϬ;&о&^Ϳо/D
ZĞƉŽƌƚŝŶŐŝƐĐĂůĐƵůĂƚĞĚŝŶƚŚĞtĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶĂƐĨŽůůŽǁƐ͗



ZĞƉŽƌƚŝŶŐс;E/оE/^ͿоϭϬ;&о&^Ϳо/Dн/d
tŚĞƌĞ͗
E/;ĐƚƵĂůEĞƚ/ŶƚĞƌĐŚĂŶŐĞͿŝƐƚŚĞĂůŐĞďƌĂŝĐƐƵŵŽĨĂĐƚƵĂůŵĞŐĂǁĂƚƚƚƌĂŶƐĨĞƌƐĂĐƌŽƐƐĂůů
dŝĞ>ŝŶĞƐĂŶĚŝŶĐůƵĚĞƐWƐĞƵĚŽͲdŝĞƐ͘ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐĚŝƌĞĐƚůLJĐŽŶŶĞĐƚĞĚǀŝĂ
ĂƐLJŶĐŚƌŽŶŽƵƐƚŝĞƐƚŽĂŶŽƚŚĞƌ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶŵĂLJŝŶĐůƵĚĞŽƌĞdžĐůƵĚĞŵĞŐĂǁĂƚƚ
ƚƌĂŶƐĨĞƌƐŽŶƚŚŽƐĞdŝĞ>ŝŶĞƐŝŶƚŚĞŝƌĂĐƚƵĂůŝŶƚĞƌĐŚĂŶŐĞ͕ƉƌŽǀŝĚĞĚƚŚĞLJĂƌĞŝŵƉůĞŵĞŶƚĞĚ
ŝŶƚŚĞƐĂŵĞŵĂŶŶĞƌĨŽƌEĞƚ/ŶƚĞƌĐŚĂŶŐĞ^ĐŚĞĚƵůĞ͘
E/^;^ĐŚĞĚƵůĞĚEĞƚ/ŶƚĞƌĐŚĂŶŐĞͿŝƐƚŚĞĂůŐĞďƌĂŝĐƐƵŵŽĨĂůůƐĐŚĞĚƵůĞĚŵĞŐĂǁĂƚƚ
ƚƌĂŶƐĨĞƌƐ͕ŝŶĐůƵĚŝŶŐLJŶĂŵŝĐ^ĐŚĞĚƵůĞƐ͕ǁŝƚŚĂĚũĂĐĞŶƚĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐ͕ĂŶĚƚĂŬŝŶŐ
ŝŶƚŽĂĐĐŽƵŶƚƚŚĞĞĨĨĞĐƚƐŽĨƐĐŚĞĚƵůĞƌĂŵƉƐ͘ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐĚŝƌĞĐƚůLJĐŽŶŶĞĐƚĞĚǀŝĂ
ĂƐLJŶĐŚƌŽŶŽƵƐƚŝĞƐƚŽĂŶŽƚŚĞƌ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶŵĂLJŝŶĐůƵĚĞŽƌĞdžĐůƵĚĞŵĞŐĂǁĂƚƚ

>ͲϬϬϮͲϮ
:ƵůLJϮϬϭϯ



WĂŐĞϰŽĨϭϭ



^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮʹŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ
ĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
ƚƌĂŶƐĨĞƌƐŽŶƚŚŽƐĞdŝĞ>ŝŶĞƐŝŶƚŚĞŝƌƐĐŚĞĚƵůĞĚ/ŶƚĞƌĐŚĂŶŐĞ͕ƉƌŽǀŝĚĞĚƚŚĞLJĂƌĞ
ŝŵƉůĞŵĞŶƚĞĚŝŶƚŚĞƐĂŵĞŵĂŶŶĞƌĨŽƌEĞƚ/ŶƚĞƌĐŚĂŶŐĞĐƚƵĂů͘
;&ƌĞƋƵĞŶĐLJŝĂƐ^ĞƚƚŝŶŐͿŝƐƚŚĞ&ƌĞƋƵĞŶĐLJŝĂƐ^ĞƚƚŝŶŐ;ŝŶŶĞŐĂƚŝǀĞDtͬϬ͘ϭ,njͿĨŽƌƚŚĞ
ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͘
ϭϬŝƐƚŚĞĐŽŶƐƚĂŶƚĨĂĐƚŽƌƚŚĂƚĐŽŶǀĞƌƚƐƚŚĞ&ƌĞƋƵĞŶĐLJŝĂƐ^ĞƚƚŝŶŐƵŶŝƚƐƚŽDtͬ,nj͘
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&^;^ĐŚĞĚƵůĞĚ&ƌĞƋƵĞŶĐLJͿŝƐϲϬ͘Ϭ,nj͕ĞdžĐĞƉƚĚƵƌŝŶŐĂƚŝŵĞĐŽƌƌĞĐƚŝŽŶ͘
/D;/ŶƚĞƌĐŚĂŶŐĞDĞƚĞƌƌƌŽƌͿŝƐƚŚĞŵĞƚĞƌĞƌƌŽƌĐŽƌƌĞĐƚŝŽŶĨĂĐƚŽƌĂŶĚƌĞƉƌĞƐĞŶƚƐƚŚĞ
ĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶƚŚĞŝŶƚĞŐƌĂƚĞĚŚŽƵƌůLJĂǀĞƌĂŐĞŽĨƚŚĞŶĞƚŝŶƚĞƌĐŚĂŶŐĞĂĐƚƵĂů;E/Ϳ
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ĞƋƵĂƚŝŽŶĨŽƌƚŚĞtĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶƚŚĂƚŵŽĚŝĨŝĞƐƚŚĞĐŽŶƚƌŽůƉŽŝŶƚĨŽƌƚŚĞ
ƉƵƌƉŽƐĞŽĨĐŽŶƚŝŶƵŽƵƐůLJƉĂLJŝŶŐďĂĐŬWƌŝŵĂƌLJ/ŶĂĚǀĞƌƚĞŶƚ/ŶƚĞƌĐŚĂŶŐĞƚŽĐŽƌƌĞĐƚ
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tĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͘
on/off peak

IATEC

= PII

accum

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ǁŚĞŶŽƉĞƌĂƚŝŶŐŝŶƵƚŽŵĂƚŝĐdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶĐŽŶƚƌŽůŵŽĚĞ͘

/dƐŚĂůůďĞnjĞƌŽǁŚĞŶŽƉĞƌĂƚŝŶŐŝŶĂŶLJŽƚŚĞƌ'ŵŽĚĞ͘
•

zсͬ^͘

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,сEƵŵďĞƌŽĨŚŽƵƌƐƵƐĞĚƚŽƉĂLJďĂĐŬWƌŝŵĂƌLJ/ŶĂĚǀĞƌƚĞŶƚ/ŶƚĞƌĐŚĂŶŐĞĞŶĞƌŐLJ͘dŚĞ
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•

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//ĂĐƚƵĂůŝƐƚŚĞŚŽƵƌůLJ/ŶĂĚǀĞƌƚĞŶƚ/ŶƚĞƌĐŚĂŶŐĞĨŽƌƚŚĞůĂƐƚŚŽƵƌ͘

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ȴdŝƐƚŚĞŚŽƵƌůLJĐŚĂŶŐĞŝŶƐLJƐƚĞŵdŝŵĞƌƌŽƌĂƐĚŝƐƚƌŝďƵƚĞĚďLJƚŚĞ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ
dŝŵĞDŽŶŝƚŽƌ͘tŚĞƌĞ͗



ȴdсdĞŶĚŚŽƵƌʹdďĞŐŝŶŚŽƵƌʹdĂĚũʹ;ƚͿΎ;dŽĨĨƐĞƚͿ

•

dĂĚũŝƐƚŚĞZĞůŝĂďŝůŝƚLJŽŽƌĚŝŶĂƚŽƌĂĚũƵƐƚŵĞŶƚĨŽƌĚŝĨĨĞƌĞŶĐĞƐǁŝƚŚ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ
dŝŵĞDŽŶŝƚŽƌĐŽŶƚƌŽůĐĞŶƚĞƌĐůŽĐŬƐ͘

•

ƚŝƐƚŚĞŶƵŵďĞƌŽĨŵŝŶƵƚĞƐŽĨDĂŶƵĂůdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶƚŚĂƚŽĐĐƵƌƌĞĚĚƵƌŝŶŐƚŚĞ
ŚŽƵƌ͘

•

dŽĨĨƐĞƚŝƐϬ͘ϬϬϬŽƌнϬ͘ϬϮϬŽƌͲϬ͘ϬϮϬ͘

•

W//ĂĐĐƵŵŝƐƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛ƐĂĐĐƵŵƵůĂƚĞĚW//ŚŽƵƌůLJŝŶDtŚ͘ŶKŶͲWĞĂŬĂŶĚ
KĨĨͲWĞĂŬĂĐĐƵŵƵůĂƚŝŽŶĂĐĐŽƵŶƚŝŶŐŝƐƌĞƋƵŝƌĞĚ͘

>ͲϬϬϮͲϮ
:ƵůLJϮϬϭϯ



WĂŐĞϱŽĨϭϭ



^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮʹŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ
ĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
tŚĞƌĞ͗

PII

on/off peak
accum

сůĂƐƚƉĞƌŝŽĚ͛Ɛ

on/off peak

PII

accum

нW//ŚŽƵƌůLJ


ůůEZ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶƐǁŝƚŚŵƵůƚŝƉůĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐŽƉĞƌĂƚĞƵƐŝŶŐƚŚĞƉƌŝŶĐŝƉůĞƐ
ŽĨdŝĞͲůŝŶĞŝĂƐ;d>ͿŽŶƚƌŽůĂŶĚƌĞƋƵŝƌĞƚŚĞƵƐĞŽĨĂŶĞƋƵĂƚŝŽŶƐŝŵŝůĂƌƚŽƚŚĞ
ZĞƉŽƌƚŝŶŐĚĞĨŝŶĞĚĂďŽǀĞ͘ŶLJŵŽĚŝĨŝĐĂƚŝŽŶ;ƐͿƚŽƚŚŝƐƐƉĞĐŝĨŝĞĚZĞƉŽƌƚŝŶŐ
ĞƋƵĂƚŝŽŶƚŚĂƚŝƐ;ĂƌĞͿŝŵƉůĞŵĞŶƚĞĚĨŽƌĂůůƐŽŶĂŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶĂŶĚŝƐ;ĂƌĞͿĐŽŶƐŝƐƚĞŶƚ
ǁŝƚŚƚŚĞĨŽůůŽǁŝŶŐĨŽƵƌƉƌŝŶĐŝƉůĞƐǁŝůůƉƌŽǀŝĚĞĂǀĂůŝĚĂůƚĞƌŶĂƚŝǀĞZĞƉŽƌƚŝŶŐĞƋƵĂƚŝŽŶ
ĐŽŶƐŝƐƚĞŶƚǁŝƚŚƚŚĞŵĞĂƐƵƌĞƐŝŶĐůƵĚĞĚŝŶƚŚŝƐƐƚĂŶĚĂƌĚ͘



>ͲϬϬϮͲϮ
:ƵůLJϮϬϭϯ

ϭ͘ ůůƉŽƌƚŝŽŶƐŽĨƚŚĞ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶĂƌĞŝŶĐůƵĚĞĚŝŶŽŶĞĂƌĞĂŽƌĂŶŽƚŚĞƌƐŽƚŚĂƚ
ƚŚĞƐƵŵŽĨĂůůĂƌĞĂŐĞŶĞƌĂƚŝŽŶ͕ůŽĂĚƐĂŶĚůŽƐƐĞƐŝƐƚŚĞƐĂŵĞĂƐƚŽƚĂůƐLJƐƚĞŵ
ŐĞŶĞƌĂƚŝŽŶ͕ůŽĂĚĂŶĚůŽƐƐĞƐ͘
Ϯ͘ dŚĞĂůŐĞďƌĂŝĐƐƵŵŽĨĂůůĂƌĞĂEĞƚ/ŶƚĞƌĐŚĂŶŐĞ^ĐŚĞĚƵůĞƐĂŶĚĂůůEĞƚ/ŶƚĞƌĐŚĂŶŐĞ
ĂĐƚƵĂůǀĂůƵĞƐŝƐĞƋƵĂůƚŽnjĞƌŽĂƚĂůůƚŝŵĞƐ͘
ϯ͘ dŚĞƵƐĞŽĨĂĐŽŵŵŽŶ^ĐŚĞĚƵůĞĚ&ƌĞƋƵĞŶĐLJ&^ĨŽƌĂůůĂƌĞĂƐĂƚĂůůƚŝŵĞƐ͘
ϰ͘ dŚĞĂďƐĞŶĐĞŽĨŵĞƚĞƌŝŶŐŽƌĐŽŵƉƵƚĂƚŝŽŶĂůĞƌƌŽƌƐ͘;dŚĞŝŶĐůƵƐŝŽŶĂŶĚƵƐĞŽĨƚŚĞ
/DƚĞƌŵƚŽĂĐĐŽƵŶƚĨŽƌŬŶŽǁŶŵĞƚĞƌŝŶŐŽƌĐŽŵƉƵƚĂƚŝŽŶĂůĞƌƌŽƌƐ͘Ϳ




WĂŐĞϲŽĨϭϭ



^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮʹŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ
ĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
͘ /ŶƚƌŽĚƵĐƚŝŽŶ
ϭ͘

dŝƚůĞ͗ ŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ&ƌŽŵ
ĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ

Ϯ͘

EƵŵďĞƌ͗ >ͲϬϬϮͲϮ

ϯ͘

WƵƌƉŽƐĞ͗ dŽĞŶƐƵƌĞƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJŽƌZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉďĂůĂŶĐĞƐ
ƌĞƐŽƵƌĐĞƐĂŶĚĚĞŵĂŶĚĂŶĚƌĞƚƵƌŶƐƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛ƐŽƌZĞƐĞƌǀĞ^ŚĂƌŝŶŐ
'ƌŽƵƉ͛ƐƌĞĂŽŶƚƌŽůƌƌŽƌƚŽĚĞĨŝŶĞĚǀĂůƵĞƐ;ƐƵďũĞĐƚƚŽĂƉƉůŝĐĂďůĞůŝŵŝƚƐͿĨŽůůŽǁŝŶŐĂ
ZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͘

ϰ͘

ƉƉůŝĐĂďŝůŝƚLJ͗
ƉƉůŝĐĂďŝůŝƚLJŝƐĚĞƚĞƌŵŝŶĞĚŽŶĂŶŝŶĚŝǀŝĚƵĂůĞǀĞŶƚďĂƐŝƐ͕ďƵƚƚŚŝƐƐƚĂŶĚĂƌĚĚŽĞƐŶŽƚ
ĂƉƉůLJƚŽĂZĞƐƉŽŶƐŝďůĞŶƚŝƚLJĚƵƌŝŶŐƉĞƌŝŽĚƐǁŚĞŶƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJŝƐŝŶŶĞƌŐLJ
ŵĞƌŐĞŶĐLJůĞƌƚ>ĞǀĞůϮŽƌ>ĞǀĞůϯ͘
ϰ͘ϭ͘ ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ
ϰ͘ϭ͘ϭ ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJƚŚĂƚŝƐĂŵĞŵďĞƌŽĨĂZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉŝƐƚŚĞ
ZĞƐƉŽŶƐŝďůĞŶƚŝƚLJŽŶůLJŝŶƉĞƌŝŽĚƐĚƵƌŝŶŐǁŚŝĐŚƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJŝƐ
ŶŽƚŝŶĂĐƚŝǀĞƐƚĂƚƵƐƵŶĚĞƌƚŚĞĂƉƉůŝĐĂďůĞĂŐƌĞĞŵĞŶƚŽƌŐŽǀĞƌŶŝŶŐƌƵůĞƐĨŽƌ
ƚŚĞZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ͘
ϰ͘Ϯ͘ ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ

ϱ͘

;WƌŽƉŽƐĞĚͿĨĨĞĐƚŝǀĞĂƚĞ͗
ϱ͘ϭ͘ &ŝƌƐƚĚĂLJŽĨƚŚĞĨŝƌƐƚĐĂůĞŶĚĂƌƋƵĂƌƚĞƌƚŚĂƚŝƐƐŝdžŵŽŶƚŚƐďĞLJŽŶĚƚŚĞĚĂƚĞƚŚĂƚ
ƚŚŝƐƐƚĂŶĚĂƌĚŝƐĂƉƉƌŽǀĞĚďLJĂƉƉůŝĐĂďůĞƌĞŐƵůĂƚŽƌLJĂƵƚŚŽƌŝƚŝĞƐ͕ŽƌŝŶƚŚŽƐĞ
ũƵƌŝƐĚŝĐƚŝŽŶƐǁŚĞƌĞƌĞŐƵůĂƚŽƌLJĂƉƉƌŽǀĂůŝƐŶŽƚƌĞƋƵŝƌĞĚ͕ƚŚĞƐƚĂŶĚĂƌĚďĞĐŽŵĞƐ
ĞĨĨĞĐƚŝǀĞƚŚĞĨŝƌƐƚĚĂLJŽĨƚŚĞĨŝƌƐƚĐĂůĞŶĚĂƌƋƵĂƌƚĞƌƚŚĂƚŝƐƐŝdžŵŽŶƚŚƐďĞLJŽŶĚƚŚĞ
ĚĂƚĞƚŚŝƐƐƚĂŶĚĂƌĚŝƐĂƉƉƌŽǀĞĚďLJƚŚĞEZŽĂƌĚŽĨdƌƵƐƚĞĞƐ͕͛ŽƌĂƐŽƚŚĞƌǁŝƐĞ
ŵĂĚĞĞĨĨĞĐƚŝǀĞƉƵƌƐƵĂŶƚƚŽƚŚĞůĂǁƐĂƉƉůŝĐĂďůĞƚŽƐƵĐŚZKŐŽǀĞƌŶŵĞŶƚĂů
ĂƵƚŚŽƌŝƚŝĞƐ͘

͘ ZĞƋƵŝƌĞŵĞŶƚƐ
Zϭ͘

dŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJĞdžƉĞƌŝĞŶĐŝŶŐĂZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐŚĂůů͕
ǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕ƌĞƚƵƌŶŝƚƐƚŽĂƚůĞĂƐƚ͗΀sŝŽůĂƚŝŽŶ
ZŝƐŬ&ĂĐƚŽƌ͗DĞĚŝƵŵ΁΀dŝŵĞ,ŽƌŝnjŽŶ͗ZĞĂůͲƚŝŵĞKƉĞƌĂƚŝŽŶƐ΁
•

>ͲϬϬϮͲϮ
:ƵůLJϮϬϭϯ

ĞƌŽ͕;ŝĨŝƚƐWƌĞͲZĞƉŽƌƚŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞǁĂƐƉŽƐŝƚŝǀĞŽƌĞƋƵĂůƚŽ
njĞƌŽͿ͗
o

ůĞƐƐƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨĂůůƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJ
ǀĞŶƚƐƚŚĂƚŽĐĐƵƌƉƌŝŽƌƚŽƚŚĂƚǀĂůƵĞŽĨZĞƉŽƌƚŝŶŐǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJ
ǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕ĂŶĚ

o

&ƵƌƚŚĞƌƌĞĚƵĐĞĚďLJƚŚĞŵĂŐŶŝƚƵĚĞŽĨƚŚĞĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶ;ŝͿƚŚĞ
ZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛ƐDŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;D^^ͿĂŶĚ;ŝŝͿƚŚĞƐƵŵ


WĂŐĞϳŽĨϭϭ



^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮʹŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ
ĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
ŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚĂůů
ƉƌĞǀŝŽƵƐĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚŚĂǀĞŶŽƚĐŽŵƉůĞƚĞĚƚŚĞŝƌ
ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚǁŚĞŶƚŚĞƐƵŵƌĞĨĞƌĞŶĐĞĚŝŶĐůĂƵƐĞ
;ŝŝͿŽĨƚŚŝƐďƵůůĞƚŝƐŐƌĞĂƚĞƌƚŚĂŶD^^͕
Kƌ͕
•

/ƚƐWƌĞͲZĞƉŽƌƚŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞ͕;ŝĨŝƚƐWƌĞͲZĞƉŽƌƚŝŶŐŽŶƚŝŶŐĞŶĐLJ
ǀĞŶƚsĂůƵĞǁĂƐŶĞŐĂƚŝǀĞͿ͕
o ůĞƐƐƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨĂůůƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJ
ǀĞŶƚƐƚŚĂƚŽĐĐƵƌƉƌŝŽƌƚŽƚŚĂƚǀĂůƵĞŽĨZĞƉŽƌƚŝŶŐǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJ
ǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕ĂŶĚ
o &ƵƌƚŚĞƌƌĞĚƵĐĞĚďLJƚŚĞŵĂŐŶŝƚƵĚĞŽĨƚŚĞĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶ;ŝͿƚŚĞ
ZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛ƐDŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;D^^ͿĂŶĚ;ŝŝͿƚŚĞƐƵŵ
ŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚĂůů
ƉƌĞǀŝŽƵƐĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚŚĂǀĞŶŽƚĐŽŵƉůĞƚĞĚƚŚĞŝƌ
ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚǁŚĞŶƚŚĞƐƵŵƌĞĨĞƌĞŶĐĞĚŝŶĐůĂƵƐĞ
;ŝŝͿŽĨƚŚŝƐďƵůůĞƚŝƐŐƌĞĂƚĞƌƚŚĂŶD^^͘

ϭ͘ϭ͘ dŚĞƌĞƋƵŝƌĞĚƌĞƉŽƌƚŝŶŐĨŽƌŵŝƐZ&Žƌŵϭ͘
ϭ͘Ϯ͘ dŚŝƐƌĞƋƵŝƌĞŵĞŶƚ;ŝŶŝƚƐĞŶƚŝƌĞƚLJͿĚŽĞƐŶŽƚĂƉƉůLJǁŚĞŶƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ
ĞdžƉĞƌŝĞŶĐŝŶŐĂZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚŝƐĞdžƉĞƌŝĞŶĐŝŶŐĂŶ
ŶĞƌŐLJŵĞƌŐĞŶĐLJůĞƌƚ>ĞǀĞůϮŽƌ>ĞǀĞůϯ͘
ZϮ͘

džĐĞƉƚĚƵƌŝŶŐƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛ƐŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚĂŶĚƚŚĞ
ZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛ƐŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚ͕ŽƌĚƵƌŝŶŐĂŶŶĞƌŐLJ
ŵĞƌŐĞŶĐLJůĞƌƚ>ĞǀĞůϮŽƌϯĨŽƌƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJĂŶĚĨŽƌĂŶĂĚĚŝƚŝŽŶĂůĨŝǀĞ
ŚŽƵƌƐĚƵƌŝŶŐĂŐŝǀĞŶĐĂůĞŶĚĂƌƋƵĂƌƚĞƌ͕ƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJƐŚĂůůŵĂŝŶƚĂŝŶĂŶ
ĂŵŽƵŶƚŽĨŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĂƚůĞĂƐƚĞƋƵĂůƚŽŝƚƐDŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ͘
΀sŝŽůĂƚŝŽŶZŝƐŬ&ĂĐƚŽƌ͗DĞĚŝƵŵ΁΀dŝŵĞ,ŽƌŝnjŽŶ͗ZĞĂůͲƚŝŵĞKƉĞƌĂƚŝŽŶƐ΁


͘ DĞĂƐƵƌĞƐ
Dϭ͘

ĂĐŚZĞƐƉŽŶƐŝďůĞŶƚŝƚLJƐŚĂůůŚĂǀĞ͕ĂŶĚƉƌŽǀŝĚĞƵƉŽŶƌĞƋƵĞƐƚ͕ĂƐĞǀŝĚĞŶĐĞ͕ĂZ
&ŽƌŵϭǁŝƚŚĚĂƚĞĂŶĚƚŝŵĞŽĨŽĐĐƵƌƌĞŶĐĞƚŽƐŚŽǁĐŽŵƉůŝĂŶĐĞǁŝƚŚZĞƋƵŝƌĞŵĞŶƚZϭ
ĂŶĚĂĚĚŝƚŝŽŶĂůĚŽĐƵŵĞŶƚĂƚŝŽŶŽĨĂŶLJĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƚŚĂƚŚĂƐŶŽƚ
ĐŽŵƉůĞƚĞĚŝƚƐŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚĂŶĚƚŚĂƚŝƐƵƐĞĚƚŽƌĞĚƵĐĞƚŚĞ
ƌĞĐŽǀĞƌLJƚŽƚŚĞĂŵŽƵŶƚůŝŵŝƚĞĚďLJD^^͘

DϮ.

ĂĐŚZĞƐƉŽŶƐŝďůĞŶƚŝƚLJƐŚĂůůŚĂǀĞĚĂƚĞĚĚŽĐƵŵĞŶƚĂƚŝŽŶƚŚĂƚĚĞŵŽŶƐƚƌĂƚĞƐŝƚƐ
ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ͕ĂǀĞƌĂŐĞĚŽǀĞƌĞĂĐŚůŽĐŬ,ŽƵƌ͕ǁĂƐŵĂŝŶƚĂŝŶĞĚŝŶĂĐĐŽƌĚĂŶĐĞ
ǁŝƚŚZĞƋƵŝƌĞŵĞŶƚZϮ͘


>ͲϬϬϮͲϮ
:ƵůLJϮϬϭϯ



WĂŐĞϴŽĨϭϭ



^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮʹŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ
ĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
͘ ŽŵƉůŝĂŶĐĞ
ϭ͘

ŽŵƉůŝĂŶĐĞDŽŶŝƚŽƌŝŶŐWƌŽĐĞƐƐ
ϭ͘ϭ͘ ŽŵƉůŝĂŶĐĞŶĨŽƌĐĞŵĞŶƚƵƚŚŽƌŝƚLJ
ƐĚĞĨŝŶĞĚŝŶƚŚĞEZZƵůĞƐŽĨWƌŽĐĞĚƵƌĞ͕͞ŽŵƉůŝĂŶĐĞŶĨŽƌĐĞŵĞŶƚƵƚŚŽƌŝƚLJ͟
ŵĞĂŶƐEZŽƌƚŚĞZĞŐŝŽŶĂůŶƚŝƚLJŝŶƚŚĞŝƌƌĞƐƉĞĐƚŝǀĞƌŽůĞƐŽĨŵŽŶŝƚŽƌŝŶŐĂŶĚ
ĞŶĨŽƌĐŝŶŐĐŽŵƉůŝĂŶĐĞǁŝƚŚƚŚĞEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚƐ͘
ϭ͘Ϯ͘ ĂƚĂZĞƚĞŶƚŝŽŶ
dŚĞĨŽůůŽǁŝŶŐĞǀŝĚĞŶĐĞƌĞƚĞŶƚŝŽŶƉĞƌŝŽĚƐŝĚĞŶƚŝĨLJƚŚĞƉĞƌŝŽĚŽĨƚŝŵĞĂŶĞŶƚŝƚLJŝƐ
ƌĞƋƵŝƌĞĚƚŽƌĞƚĂŝŶƐƉĞĐŝĨŝĐĞǀŝĚĞŶĐĞƚŽĚĞŵŽŶƐƚƌĂƚĞĐŽŵƉůŝĂŶĐĞ͘&ŽƌŝŶƐƚĂŶĐĞƐ
ǁŚĞƌĞƚŚĞĞǀŝĚĞŶĐĞƌĞƚĞŶƚŝŽŶƉĞƌŝŽĚƐƉĞĐŝĨŝĞĚďĞůŽǁŝƐƐŚŽƌƚĞƌƚŚĂŶƚŚĞƚŝŵĞ
ƐŝŶĐĞƚŚĞůĂƐƚĂƵĚŝƚ͕ƚŚĞŽŵƉůŝĂŶĐĞŶĨŽƌĐĞŵĞŶƚƵƚŚŽƌŝƚLJŵĂLJĂƐŬĂŶĞŶƚŝƚLJƚŽ
ƉƌŽǀŝĚĞŽƚŚĞƌĞǀŝĚĞŶĐĞƚŽƐŚŽǁƚŚĂƚŝƚǁĂƐĐŽŵƉůŝĂŶƚĨŽƌƚŚĞĨƵůůͲƚŝŵĞƉĞƌŝŽĚ
ƐŝŶĐĞƚŚĞůĂƐƚĂƵĚŝƚ͘
dŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJƐŚĂůůƌĞƚĂŝŶĚĂƚĂŽƌĞǀŝĚĞŶĐĞƚŽƐŚŽǁĐŽŵƉůŝĂŶĐĞĨŽƌƚŚĞ
ĐƵƌƌĞŶƚLJĞĂƌ͕ƉůƵƐƚŚƌĞĞƉƌĞǀŝŽƵƐĐĂůĞŶĚĂƌLJĞĂƌƐ͕ƵŶůĞƐƐĚŝƌĞĐƚĞĚďLJŝƚƐ
ŽŵƉůŝĂŶĐĞŶĨŽƌĐĞŵĞŶƚƵƚŚŽƌŝƚLJƚŽƌĞƚĂŝŶƐƉĞĐŝĨŝĐĞǀŝĚĞŶĐĞĨŽƌĂůŽŶŐĞƌ
ƉĞƌŝŽĚŽĨƚŝŵĞĂƐƉĂƌƚŽĨĂŶŝŶǀĞƐƚŝŐĂƚŝŽŶ͘
/ĨĂZĞƐƉŽŶƐŝďůĞŶƚŝƚLJŝƐĨŽƵŶĚŶŽŶĐŽŵƉůŝĂŶƚ͕ŝƚƐŚĂůůŬĞĞƉŝŶĨŽƌŵĂƚŝŽŶƌĞůĂƚĞĚƚŽ
ƚŚĞŶŽŶĐŽŵƉůŝĂŶĐĞƵŶƚŝůĨŽƵŶĚĐŽŵƉůŝĂŶƚ͕ŽƌĨŽƌƚŚĞƚŝŵĞƉĞƌŝŽĚƐƉĞĐŝĨŝĞĚĂďŽǀĞ͕
ǁŚŝĐŚĞǀĞƌŝƐůŽŶŐĞƌ͘
dŚĞŽŵƉůŝĂŶĐĞŶĨŽƌĐĞŵĞŶƚƵƚŚŽƌŝƚLJƐŚĂůůŬĞĞƉƚŚĞůĂƐƚĂƵĚŝƚƌĞĐŽƌĚƐĂŶĚĂůů
ƐƵďƐĞƋƵĞŶƚƌĞƋƵĞƐƚĞĚĂŶĚƐƵďŵŝƚƚĞĚƌĞĐŽƌĚƐ͘
ϭ͘ϯ͘ ŽŵƉůŝĂŶĐĞDŽŶŝƚŽƌŝŶŐĂŶĚƐƐĞƐƐŵĞŶƚWƌŽĐĞƐƐĞƐ
ŽŵƉůŝĂŶĐĞƵĚŝƚƐ
^ĞůĨͲĞƌƚŝĨŝĐĂƚŝŽŶƐ
^ƉŽƚŚĞĐŬŝŶŐ
ŽŵƉůŝĂŶĐĞ/ŶǀĞƐƚŝŐĂƚŝŽŶƐ
^ĞůĨͲZĞƉŽƌƚŝŶŐ
ŽŵƉůĂŝŶƚƐ
ϭ͘ϰ͘ ĚĚŝƚŝŽŶĂůŽŵƉůŝĂŶĐĞ/ŶĨŽƌŵĂƚŝŽŶ
dŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJŵĂLJƵƐĞŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌĂŶLJĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚĂƐƌĞƋƵŝƌĞĚĨŽƌĂŶLJŽƚŚĞƌĂƉƉůŝĐĂďůĞƐƚĂŶĚĂƌĚƐ͘
ZĞƐƉŽŶƐŝďůĞŶƚŝƚLJŝƐŶŽƚƐƵďũĞĐƚƚŽĐŽŵƉůŝĂŶĐĞǁŝƚŚƚŚŝƐƐƚĂŶĚĂƌĚŝŶĂŶLJƉĞƌŝŽĚ
ĚƵƌŝŶŐǁŚŝĐŚƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJŝƐŝŶĂŶŶĞƌŐLJŵĞƌŐĞŶĐLJůĞƌƚ>ĞǀĞůϮŽƌ
>ĞǀĞůϯ͘

>ͲϬϬϮͲϮ
:ƵůLJϮϬϭϯ



WĂŐĞϵŽĨϭϭ



^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮʹŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ
ĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ

Ϯ͘

sŝŽůĂƚŝŽŶ^ĞǀĞƌŝƚLJ>ĞǀĞůƐ
Zη

>ŽǁĞƌs^>

DŽĚĞƌĂƚĞs^>

,ŝŐŚs^>

^ĞǀĞƌĞs^>

Zϭ

dŚĞZĞƐƉŽŶƐŝďůĞ
ŶƚŝƚLJƌĞĐŽǀĞƌĞĚ
ƉĂƌƚŝĂůůLJĨƌŽŵĂ
ZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJ
ǀĞŶƚĚƵƌŝŶŐƚŚĞ
ŽŶƚŝŶŐĞŶĐLJ
ǀĞŶƚZĞĐŽǀĞƌLJ
WĞƌŝŽĚďƵƚ
ƌĞĐŽǀĞƌĞĚůĞƐƐ
ƚŚĂŶϭϬϬйďƵƚ
ŵŽƌĞƚŚĂŶϵϬй
ŽĨƌĞƋƵŝƌĞĚ
ƌĞĐŽǀĞƌLJ͘

dŚĞZĞƐƉŽŶƐŝďůĞ
ŶƚŝƚLJƌĞĐŽǀĞƌĞĚ
ƉĂƌƚŝĂůůLJĨƌŽŵĂ
ZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJ
ǀĞŶƚĚƵƌŝŶŐƚŚĞ
ŽŶƚŝŶŐĞŶĐLJ
ǀĞŶƚZĞĐŽǀĞƌLJ
WĞƌŝŽĚďƵƚ
ƌĞĐŽǀĞƌĞĚϵϬйŽƌ
ůĞƐƐďƵƚŵŽƌĞ
ƚŚĂŶϴϬйŽĨ
ƌĞƋƵŝƌĞĚ
ƌĞĐŽǀĞƌLJ͘

dŚĞZĞƐƉŽŶƐŝďůĞ
ŶƚŝƚLJƌĞĐŽǀĞƌĞĚ
ƉĂƌƚŝĂůůLJĨƌŽŵĂ
ZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJ
ǀĞŶƚĚƵƌŝŶŐƚŚĞ
ŽŶƚŝŶŐĞŶĐLJ
ǀĞŶƚZĞĐŽǀĞƌLJ
WĞƌŝŽĚďƵƚ
ƌĞĐŽǀĞƌĞĚϴϬйŽƌ
ůĞƐƐďƵƚŵŽƌĞ
ƚŚĂŶϳϬйŽĨ
ƌĞƋƵŝƌĞĚ
ƌĞĐŽǀĞƌLJ͘

dŚĞZĞƐƉŽŶƐŝďůĞ
ŶƚŝƚLJƌĞĐŽǀĞƌĞĚ
ƉĂƌƚŝĂůůLJĨƌŽŵĂ
ZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJ
ǀĞŶƚĚƵƌŝŶŐƚŚĞ
ŽŶƚŝŶŐĞŶĐLJ
ǀĞŶƚZĞĐŽǀĞƌLJ
WĞƌŝŽĚďƵƚ
ƌĞĐŽǀĞƌĞĚϳϬйŽƌ
ůĞƐƐŽĨƌĞƋƵŝƌĞĚ
ƌĞĐŽǀĞƌLJ͘

ZϮ

/ŶĞĂĐŚĐĂůĞŶĚĂƌ
ƋƵĂƌƚĞƌ͕ƚŚĞ
ZĞƐƉŽŶƐŝďůĞ
ŶƚŝƚLJŚĂĚ
ŽŶƚŝŶŐĞŶĐLJ
ZĞƐĞƌǀĞƐďƵƚŝƚƐ
ŽŶƚŝŶŐĞŶĐLJ
ZĞƐĞƌǀĞǁĂƐ
ĚĞĨŝĐŝĞŶƚĨŽƌ
ŵŽƌĞƚŚĂŶϱ
ŚŽƵƌƐďƵƚůĞƐƐ
ƚŚĂŶŽƌĞƋƵĂůƚŽ
ϭϱŚŽƵƌƐ͘

/ŶĞĂĐŚĐĂůĞŶĚĂƌ
ƋƵĂƌƚĞƌ͕ƚŚĞ
ZĞƐƉŽŶƐŝďůĞ
ŶƚŝƚLJŚĂĚ
ŽŶƚŝŶŐĞŶĐLJ
ZĞƐĞƌǀĞƐďƵƚŝƚƐ
ŽŶƚŝŶŐĞŶĐLJ
ZĞƐĞƌǀĞǁĂƐ
ĚĞĨŝĐŝĞŶƚĨŽƌ
ŵŽƌĞƚŚĂŶϭϱ
ŚŽƵƌƐďƵƚůĞƐƐ
ƚŚĂŶŽƌĞƋƵĂůƚŽ
ϮϱŚŽƵƌƐ͘

/ŶĞĂĐŚĐĂůĞŶĚĂƌ
ƋƵĂƌƚĞƌ͕ƚŚĞ
ZĞƐƉŽŶƐŝďůĞ
ŶƚŝƚLJŚĂĚ
ŽŶƚŝŶŐĞŶĐLJ
ZĞƐĞƌǀĞƐďƵƚŝƚƐ
ŽŶƚŝŶŐĞŶĐLJ
ZĞƐĞƌǀĞǁĂƐ
ĚĞĨŝĐŝĞŶƚĨŽƌ
ŵŽƌĞƚŚĂŶϮϱ
ŚŽƵƌƐďƵƚůĞƐƐ
ƚŚĂŶŽƌĞƋƵĂůƚŽ
ϯϱŚŽƵƌƐ͘

/ŶĞĂĐŚĐĂůĞŶĚĂƌ
ƋƵĂƌƚĞƌ͕ƚŚĞ
ZĞƐƉŽŶƐŝďůĞ
ŶƚŝƚLJŚĂĚ
ŽŶƚŝŶŐĞŶĐLJ
ZĞƐĞƌǀĞƐďƵƚŝƚƐ
ŽŶƚŝŶŐĞŶĐLJ
ZĞƐĞƌǀĞǁĂƐ
ĚĞĨŝĐŝĞŶƚĨŽƌ
ŵŽƌĞƚŚĂŶϯϱ
ŚŽƵƌƐ͘


͘ ZĞŐŝŽŶĂůsĂƌŝĂŶĐĞƐ
EŽŶĞ͘
&͘ ƐƐŽĐŝĂƚĞĚŽĐƵŵĞŶƚƐ
>ͲϬϬϮͲϮŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
ĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
Z&Žƌŵϭ

>ͲϬϬϮͲϮ
:ƵůLJϮϬϭϯ



WĂŐĞϭϬŽĨϭϭ



^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮʹŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ
ĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
sĞƌƐŝŽŶ,ŝƐƚŽƌLJ
sĞƌƐŝŽŶ

ĂƚĞ

ĐƚŝŽŶ

ŚĂŶŐĞdƌĂĐŬŝŶŐ

Ϭ

Ɖƌŝůϭ͕ϮϬϬϱ

ĨĨĞĐƚŝǀĞĂƚĞ

EĞǁ

Ϭ

ƵŐƵƐƚϴ͕ϮϬϬϱ ZĞŵŽǀĞĚ͞WƌŽƉŽƐĞĚ͟ĨƌŽŵĨĨĞĐƚŝǀĞ
ĂƚĞ

ƌƌĂƚĂ

Ϭ

&ĞďƌƵĂƌLJϭϰ͕
ϮϬϬϲ

ZĞǀŝƐĞĚŐƌĂƉŚŽŶƉĂŐĞϯ͕͞ϭϬŵŝŶ͘͟ƚŽ
͞ZĞĐŽǀĞƌLJƚŝŵĞ͘͟ZĞŵŽǀĞĚĨŽƵƌƚŚ
ďƵůůĞƚ͘

ƌƌĂƚĂ

Ϯ



EZKdĚŽƉƚŝŽŶ

ŽŵƉůĞƚĞƌĞǀŝƐŝŽŶ



















>ͲϬϬϮͲϮ
:ƵůLJϮϬϭϯ



WĂŐĞϭϭŽĨϭϭ



^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮʹŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ
ĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
^ƚĂŶĚĂƌĚĞǀĞůŽƉŵĞŶƚZŽĂĚŵĂƉ
dŚŝƐƐĞĐƚŝŽŶŝƐŵĂŝŶƚĂŝŶĞĚďLJƚŚĞĚƌĂĨƚŝŶŐƚĞĂŵĚƵƌŝŶŐƚŚĞĚĞǀĞůŽƉŵĞŶƚŽĨƚŚĞƐƚĂŶĚĂƌĚĂŶĚǁŝůů
ďĞƌĞŵŽǀĞĚǁŚĞŶƚŚĞƐƚĂŶĚĂƌĚďĞĐŽŵĞƐĞĨĨĞĐƚŝǀĞ͘
ĞǀĞůŽƉŵĞŶƚ^ƚĞƉƐŽŵƉůĞƚĞĚ͗
ϭ͘ dŚĞ^ZĨŽƌWƌŽũĞĐƚϮϬϬϳͲϭϴ͕ZĞůŝĂďŝůŝƚLJĂƐĞĚŽŶƚƌŽůƐ͕ǁĂƐƉŽƐƚĞĚĨŽƌĂϯϬͲĚĂLJĨŽƌŵĂů
ĐŽŵŵĞŶƚƉĞƌŝŽĚŽŶDĂLJϭϱ͕ϮϬϬϳ͘
Ϯ͘ ƌĞǀŝƐĞĚ^ZĨŽƌWƌŽũĞĐƚϮϬϬϳͲϬϱ͕ZĞůŝĂďŝůŝƚLJĂƐĞĚŽŶƚƌŽůƐ͕ǁĂƐƉŽƐƚĞĚĨŽƌĂƐĞĐŽŶĚ
ϯϬͲĚĂLJĨŽƌŵĂůĐŽŵŵĞŶƚƉĞƌŝŽĚŽŶ^ĞƉƚĞŵďĞƌϭϬ͕ϮϬϬϳ͘
ϯ͘ dŚĞ^ƚĂŶĚĂƌĚƐŽŵŵŝƚƚĞĞĂƉƉƌŽǀĞĚWƌŽũĞĐƚϮϬϬϳͲϭϴ͕ZĞůŝĂďŝůŝƚLJĂƐĞĚŽŶƚƌŽůƐ͕ƚŽďĞ
ŵŽǀĞĚƚŽƐƚĂŶĚĂƌĚĚƌĂĨƚŝŶŐŽŶĞĐĞŵďĞƌϭϭ͕ϮϬϬϳ͘
ϰ͘ dŚĞ^ZĨŽƌWƌŽũĞĐƚϮϬϬϳͲϬϱ͕ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJŽŶƚƌŽůƐ͕ǁĂƐƉŽƐƚĞĚĨŽƌĂϯϬͲĚĂLJ
ĨŽƌŵĂůĐŽŵŵĞŶƚƉĞƌŝŽĚŽŶ:ƵůLJϯ͕ϮϬϬϳ͘
ϱ͘ dŚĞ^ƚĂŶĚĂƌĚƐŽŵŵŝƚƚĞĞĂƉƉƌŽǀĞĚWƌŽũĞĐƚϮϬϬϳͲϬϱ͕ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJŽŶƚƌŽůƐ͕ƚŽ
ďĞŵŽǀĞĚƚŽƐƚĂŶĚĂƌĚĚƌĂĨƚŝŶŐŽŶ:ĂŶƵĂƌLJϭϴ͕ϮϬϬϴ͘
ϲ͘ dŚĞ^ƚĂŶĚĂƌĚƐŽŵŵŝƚƚĞĞĂƉƉƌŽǀĞĚƚŚĞŵĞƌŐĞƌŽĨWƌŽũĞĐƚϮϬϬϳͲϬϱ͕ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ
ŽŶƚƌŽůƐ͕ĂŶĚWƌŽũĞĐƚϮϬϬϳͲϭϴ͕ZĞůŝĂďŝůŝƚLJͲďĂƐĞĚŽŶƚƌŽů͕ĂƐWƌŽũĞĐƚϮϬϭϬͲϭϰ͕ĂůĂŶĐŝŶŐ
ƵƚŚŽƌŝƚLJZĞůŝĂďŝůŝƚLJͲďĂƐĞĚŽŶƚƌŽůƐŽŶ:ƵůLJϮϴ͕ϮϬϭϬ͘
ϳ͘ dŚĞEZ^ƚĂŶĚĂƌĚƐŽŵŵŝƚƚĞĞĂƉƉƌŽǀĞĚďƌĞĂŬŝŶŐWƌŽũĞĐƚϮϬϭϬͲϭϰ͕ĂůĂŶĐŝŶŐ
ƵƚŚŽƌŝƚLJZĞůŝĂďŝůŝƚLJͲďĂƐĞĚŽŶƚƌŽůƐ͕ŝŶƚŽƚǁŽƉŚĂƐĞƐĂŶĚŵŽǀŝŶŐWŚĂƐĞϭ;WƌŽũĞĐƚϮϬϭϬͲ
ϭϰ͘ϭ͕ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJZĞůŝĂďŝůŝƚLJͲďĂƐĞĚŽŶƚƌŽůƐʹZĞƐĞƌǀĞƐͿŝŶƚŽĨŽƌŵĂůƐƚĂŶĚĂƌĚƐ
ĚĞǀĞůŽƉŵĞŶƚŽŶ:ƵůLJϭϯ͕ϮϬϭϭ͘
ϴ͘ dŚĞĚƌĂĨƚƐƚĂŶĚĂƌĚǁĂƐƉŽƐƚĞĚĨŽƌϯϬͲĚĂLJĨŽƌŵĂůŝŶĚƵƐƚƌLJĐŽŵŵĞŶƚƉĞƌŝŽĚĨƌŽŵ:ƵŶĞϰ͕
ϮϬϭϮƚŚƌŽƵŐŚ:ƵůLJϯ͕ϮϬϭϮ͘
ϵ͘ dŚĞĚƌĂĨƚƐƚĂŶĚĂƌĚǁĂƐƉŽƐƚĞĚĨŽƌϰϱͲĚĂLJĨŽƌŵĂůŝŶĚƵƐƚƌLJĐŽŵŵĞŶƚƉĞƌŝŽĚĂŶĚŝŶŝƚŝĂů
ďĂůůŽƚĨƌŽŵDĂƌĐŚϭϮ͕ϮϬϭϯƚŚƌŽƵŐŚƉƌŝůϮϱ͕ϮϬϭϯ͘

WƌŽƉŽƐĞĚĐƚŝŽŶWůĂŶĂŶĚĞƐĐƌŝƉƚŝŽŶŽĨƵƌƌĞŶƚƌĂĨƚ͗
dŚŝƐŝƐƚŚĞƚŚŝƌĚƉŽƐƚŝŶŐŽĨƚŚĞƉƌŽƉŽƐĞĚƐƚĂŶĚĂƌĚ͘dŚŝƐƉƌŽƉŽƐĞĚĚƌĂĨƚƐƚĂŶĚĂƌĚǁŝůůďĞƉŽƐƚĞĚ
ĨŽƌĂϰϱͲĚĂLJĨŽƌŵĂůĐŽŵŵĞŶƚƉĞƌŝŽĚĂŶĚϭϬͲĚĂLJƐƵĐĐĞƐƐŝǀĞďĂůůŽƚ͘

&ƵƚƵƌĞĞǀĞůŽƉŵĞŶƚWůĂŶ͗
ŶƚŝĐŝƉĂƚĞĚĐƚŝŽŶƐ
ϭ͘ dŚŝƌĚƉŽƐƚŝŶŐ

:ƵůLJͬƵŐƵƐƚϮϬϭϯ

Ϯ͘ ^ƵĐĐĞƐƐŝǀĞĂůůŽƚ

>ͲϬϬϮͲϮ
:ƵůLJϮϬϭϯ

ŶƚŝĐŝƉĂƚĞĚĂƚĞ

ƵŐƵƐƚϮϬϭϯ



WĂŐĞϭŽĨϭϭ



^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮʹŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ
ĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
ϯ͘ ZĞĐŝƌĐƵůĂƚŝŽŶĂůůŽƚ

KĐƚŽďĞƌϮϬϭϯ

ϰ͘ EZKdĂĚŽƉƚŝŽŶ͘

EŽǀĞŵďĞƌϮϬϭϯ




>ͲϬϬϮͲϮ
:ƵůLJϮϬϭϯ





WĂŐĞϮŽĨϭϭ



^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮʹŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ
ĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ

ĞĨŝŶŝƚŝŽŶƐŽĨdĞƌŵƐhƐĞĚŝŶ^ƚĂŶĚĂƌĚ
dŚŝƐƐĞĐƚŝŽŶŝŶĐůƵĚĞƐĂůůŶĞǁůLJĚĞĨŝŶĞĚŽƌƌĞǀŝƐĞĚƚĞƌŵƐƵƐĞĚŝŶƚŚĞƉƌŽƉŽƐĞĚƐƚĂŶĚĂƌĚ͘dĞƌŵƐ
ĂůƌĞĂĚLJĚĞĨŝŶĞĚŝŶƚŚĞZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚƐ'ůŽƐƐĂƌLJŽĨdĞƌŵƐĂƌĞŶŽƚƌĞƉĞĂƚĞĚŚĞƌĞ͘EĞǁŽƌ
ƌĞǀŝƐĞĚĚĞĨŝŶŝƚŝŽŶƐůŝƐƚĞĚďĞůŽǁďĞĐŽŵĞĂƉƉƌŽǀĞĚǁŚĞŶƚŚĞƉƌŽƉŽƐĞĚƐƚĂŶĚĂƌĚŝƐĂƉƉƌŽǀĞĚ͘
tŚĞŶƚŚĞƐƚĂŶĚĂƌĚďĞĐŽŵĞƐĞĨĨĞĐƚŝǀĞ͕ƚŚĞƐĞĚĞĨŝŶĞĚƚĞƌŵƐǁŝůůďĞƌĞŵŽǀĞĚĨƌŽŵƚŚĞŝŶĚŝǀŝĚƵĂů
ƐƚĂŶĚĂƌĚĂŶĚĂĚĚĞĚƚŽƚŚĞ'ůŽƐƐĂƌLJ͘
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͗ŶLJƐŝŶŐůĞĞǀĞŶƚĚĞƐĐƌŝďĞĚŝŶ^ƵďƐĞĐƚŝŽŶƐ;Ϳ͕;Ϳ͕Žƌ;ͿďĞůŽǁ͕
ŽƌĂŶLJƐĞƌŝĞƐŽĨƐƵĐŚŽƚŚĞƌǁŝƐĞƐŝŶŐůĞĞǀĞŶƚƐ͕ǁŝƚŚĞĂĐŚƐĞƉĂƌĂƚĞĚĨƌŽŵƚŚĞŶĞdžƚďLJůĞƐƐƚŚĂŶ
ŽŶĞŵŝŶƵƚĞ͘
͘ ^ƵĚĚĞŶ>ŽƐƐŽĨŐĞŶĞƌĂƚŝŽŶ͗
Ă͘ ƵĞƚŽ
ŝ͘ hŶŝƚƚƌŝƉƉŝŶŐ͕
ŝŝ͘ >ŽƐƐŽĨŐĞŶĞƌĂƚŽƌ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ&ĂĐŝůŝƚLJƌĞƐƵůƚŝŶŐŝŶŝƐŽůĂƚŝŽŶŽĨƚŚĞ
ŐĞŶĞƌĂƚŽƌĨƌŽŵƚŚĞƵůŬůĞĐƚƌŝĐ^LJƐƚĞŵŽƌĨƌŽŵƚŚĞƌĞƐƉŽŶƐŝďůĞĞŶƚŝƚLJ͛Ɛ
ĞůĞĐƚƌŝĐƐLJƐƚĞŵ͕Žƌ
ŝŝŝ͘ ^ƵĚĚĞŶƵŶƉůĂŶŶĞĚŽƵƚĂŐĞŽĨƚƌĂŶƐŵŝƐƐŝŽŶ&ĂĐŝůŝƚLJ͖
ď͘ ŶĚ͕ƚŚĂƚĐĂƵƐĞƐĂŶƵŶĞdžƉĞĐƚĞĚĐŚĂŶŐĞƚŽƚŚĞƌĞƐƉŽŶƐŝďůĞĞŶƚŝƚLJ͛Ɛ͖
͘ ^ƵĚĚĞŶůŽƐƐŽĨĂŶŝŵƉŽƌƚ͕ĚƵĞƚŽĨŽƌĐĞĚŽƵƚĂŐĞŽĨƚƌĂŶƐŵŝƐƐŝŽŶĞƋƵŝƉŵĞŶƚƚŚĂƚĐĂƵƐĞƐ
ĂŶƵŶĞdžƉĞĐƚĞĚŝŵďĂůĂŶĐĞďĞƚǁĞĞŶŐĞŶĞƌĂƚŝŽŶĂŶĚůŽĂĚŽŶƚŚĞ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶĐŚĂŶŐĞ
ƚŽƚŚĞƌĞƐƉŽŶƐŝďůĞĞŶƚŝƚLJ͛Ɛ͘
C. ^ƵĚĚĞŶƌĞƐƚŽƌĂƚŝŽŶůŽƐƐŽĨĂŬŶŽǁŶůŽĂĚƚŚĂƚǁĂƐƵƐĞĚĂƐĂƌĞƐŽƵƌĐĞƚŚĂƚĐĂƵƐĞƐĂŶ
ƵŶĞdžƉĞĐƚĞĚĐŚĂŶŐĞƚŽƚŚĞƌĞƐƉŽŶƐŝďůĞĞŶƚŝƚLJ͛Ɛ͘
DŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;D^^Ϳ͗dŚĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͕ĚƵĞƚŽĂƐŝŶŐůĞ
ĐŽŶƚŝŶŐĞŶĐLJ͕ƚŚĂƚǁŽƵůĚƌĞƐƵůƚŝŶƚŚĞŐƌĞĂƚĞƐƚůŽƐƐ;ŵĞĂƐƵƌĞĚŝŶDtͿŽĨƌĞƐŽƵƌĐĞŽƵƚƉƵƚƵƐĞĚ
ďLJƚŚĞZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ;Z^'ͿŽƌĂĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJƚŚĂƚŝƐŶŽƚƉĂƌƚŝĐŝƉĂƚŝŶŐĂƐĂ
ŵĞŵďĞƌŽĨĂZ^'ĂƚƚŚĞƚŝŵĞŽĨƚŚĞĞǀĞŶƚƚŽŵĞĞƚĨŝƌŵƐLJƐƚĞŵůŽĂĚĂŶĚĞdžƉŽƌƚŽďůŝŐĂƚŝŽŶ
;ĞdžĐůƵĚŝŶŐĞdžƉŽƌƚŽďůŝŐĂƚŝŽŶĨŽƌǁŚŝĐŚŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞŽďůŝŐĂƚŝŽŶƐĂƌĞďĞŝŶŐŵĞƚďLJƚŚĞ
ƐŝŶŬĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJͿ͘
ZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͗ŶLJĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƌĞƐƵůƚŝŶŐŝŶĂůŽƐƐ
ŽĨDtŽƵƚƉƵƚŐƌĞĂƚĞƌƚŚĂŶŽƌĞƋƵĂůƚŽƚŚĞůĞƐƐĞƌĂŵŽƵŶƚŽĨϴϬƉĞƌĐĞŶƚŽĨƚŚĞDŽƐƚ^ĞǀĞƌĞ
^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJŽƌƚŚĞĂŵŽƵŶƚůŝƐƚĞĚďĞůŽǁĨŽƌƚŚĞĂƉƉůŝĐĂďůĞ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶϱϬϬDtĂŶĚ
ŽĐĐƵƌƌŝŶŐǁŝƚŚŝŶĂƌŽůůŝŶŐŽŶĞͲŵŝŶƵƚĞŝŶƚĞƌǀĂůďĂƐĞĚŽŶD^ƐĐĂŶƌĂƚĞĚĂƚĂ͘dŚĞϴϬйƚŚƌĞƐŚŽůĚ
ŵĂLJďĞƌĞĚƵĐĞĚƵƉŽŶǁƌŝƚƚĞŶŶŽƚŝĨŝĐĂƚŝŽŶƚŽƚŚĞZĞŐŝŽŶĂůŶƚŝƚLJ͘
•

ĂƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶͲϵϬϬDt

•

tĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶʹϱϬϬDt

•

ZKdʹϴϬϬDt

•

YƵĞďĞĐʹϱϬϬDt

>ͲϬϬϮͲϮ
:ƵůLJϮϬϭϯ



WĂŐĞϯŽĨϭϭ



^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮʹŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ
ĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͗ƉĞƌŝŽĚďĞŐŝŶŶŝŶŐĂƚƚŚĞƚŝŵĞƚŚĂƚƚŚĞƌĞƐŽƵƌĐĞŽƵƚƉƵƚ
ďĞŐŝŶƐƚŽĚĞĐůŝŶĞǁŝƚŚŝŶƚŚĞĨŝƌƐƚŽŶĞͲŵŝŶƵƚĞŝŶƚĞƌǀĂůƚŚĂƚĚĞĨŝŶĞƐĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJ
ǀĞŶƚ͕ĂŶĚĞdžƚĞŶĚƐĨŽƌĨŝĨƚĞĞŶŵŝŶƵƚĞƐƚŚĞƌĞĂĨƚĞƌ͘
ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚ͗ƉĞƌŝŽĚŶŽƚĞdžĐĞĞĚŝŶŐϵϬŵŝŶƵƚĞƐĨŽůůŽǁŝŶŐƚŚĞĞŶĚ
ŽĨƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͘
WƌĞͲZĞƉŽƌƚŝŶŐĂďůĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞ͗dŚĞĂǀĞƌĂŐĞǀĂůƵĞŽĨZĞƉŽƌƚŝŶŐ͕Žƌ
ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉZĞƉŽƌƚŝŶŐǁŚĞŶĂƉƉůŝĐĂďůĞ͕ŝŶƚŚĞϭϲƐĞĐŽŶĚŝŶƚĞƌǀĂůŝŵŵĞĚŝĂƚĞůLJ
ƉƌŝŽƌƚŽƚŚĞƐƚĂƌƚŽĨƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚďĂƐĞĚŽŶD^ƐĐĂŶƌĂƚĞĚĂƚĂ͘
ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉZĞƉŽƌƚŝŶŐ͗ƚĂŶLJŐŝǀĞŶƚŝŵĞŽĨŵĞĂƐƵƌĞŵĞŶƚĨŽƌƚŚĞĂƉƉůŝĐĂďůĞ
ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ͕ƚŚĞĂůŐĞďƌĂŝĐƐƵŵŽĨƚŚĞƐ;ŽƌĞƋƵŝǀĂůĞŶƚĂƐĐĂůĐƵůĂƚĞĚĂƚƐƵĐŚƚŝŵĞ
ŽĨŵĞĂƐƵƌĞŵĞŶƚͿŽĨĂůůŽĨƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐƉĂƌƚŝĐŝƉĂƚŝŶŐŝŶƚŚĂƚŵĂŬĞƵƉƚŚĞZĞƐĞƌǀĞ
^ŚĂƌŝŶŐ'ƌŽƵƉĂƚƚŚĞƚŝŵĞŽĨŵĞĂƐƵƌĞŵĞŶƚ͘

ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ͗dŚĞƉƌŽǀŝƐŝŽŶŽĨĐĂƉĂĐŝƚLJƚŚĂƚŵĂLJďĞĚĞƉůŽLJĞĚďLJƚŚĞĂůĂŶĐŝŶŐ
ƵƚŚŽƌŝƚLJƚŽƌĞƐƉŽŶĚƚŽĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚŽƚŚĞƌĐŽŶƚŝŶŐĞŶĐLJƌĞƋƵŝƌĞŵĞŶƚƐ
;ƐƵĐŚĂƐŶĞƌŐLJŵĞƌŐĞŶĐLJůĞƌƚƐ>ĞǀĞůϮŽƌ>ĞǀĞůϯͿĂƐƐƉĞĐŝĨŝĞĚŝŶƚŚĞĂƐƐŽĐŝĂƚĞĚKW
ƐƚĂŶĚĂƌĚͿ͘dŚĞĐĂƉĂĐŝƚLJŵĂLJďĞƉƌŽǀŝĚĞĚďLJƌĞƐŽƵƌĐĞƐƐƵĐŚĂƐĞŵĂŶĚ^ŝĚĞDĂŶĂŐĞŵĞŶƚ
;^DͿ͕/ŶƚĞƌƌƵƉƚŝďůĞ>ŽĂĚĂŶĚƵŶůŽĂĚĞĚŐĞŶĞƌĂƚŝŽŶ͘

ZĞƉŽƌƚŝŶŐ͗dŚĞƐĐĂŶƌĂƚĞǀĂůƵĞƐŽĨĂĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛ƐƌĞĂŽŶƚƌŽůƌƌŽƌ;Ϳ
ŵĞĂƐƵƌĞĚŝŶDt͕ǁŚŝĐŚŝŶĐůƵĚĞƐƚŚĞĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛ƐEĞƚĐƚƵĂů
/ŶƚĞƌĐŚĂŶŐĞĂŶĚŝƚƐEĞƚ^ĐŚĞĚƵůĞĚ/ŶƚĞƌĐŚĂŶŐĞ͕ƉůƵƐŝƚƐ&ƌĞƋƵĞŶĐLJŝĂƐŽďůŝŐĂƚŝŽŶ͕ƉůƵƐĂŶLJ
ŬŶŽǁŶŵĞƚĞƌĞƌƌŽƌ͘/ŶƚŚĞtĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͕ZĞƉŽƌƚŝŶŐŝŶĐůƵĚĞƐƵƚŽŵĂƚŝĐdŝŵĞ
ƌƌŽƌŽƌƌĞĐƚŝŽŶ;dͿ͘
ZĞƉŽƌƚŝŶŐŝƐĐĂůĐƵůĂƚĞĚĂƐĨŽůůŽǁƐ͗


ZĞƉŽƌƚŝŶŐс;E/оE/^ͿоϭϬ;&о&^Ϳо/D
ZĞƉŽƌƚŝŶŐŝƐĐĂůĐƵůĂƚĞĚŝŶƚŚĞtĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶĂƐĨŽůůŽǁƐ͗



ZĞƉŽƌƚŝŶŐс;E/оE/^ͿоϭϬ;&о&^Ϳо/Dн/d
tŚĞƌĞ͗
E/;ĐƚƵĂůEĞƚ/ŶƚĞƌĐŚĂŶŐĞͿŝƐƚŚĞĂůŐĞďƌĂŝĐƐƵŵŽĨĂĐƚƵĂůŵĞŐĂǁĂƚƚƚƌĂŶƐĨĞƌƐĂĐƌŽƐƐĂůů
dŝĞ>ŝŶĞƐĂŶĚŝŶĐůƵĚĞƐWƐĞƵĚŽͲdŝĞƐ͘ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐĚŝƌĞĐƚůLJĐŽŶŶĞĐƚĞĚǀŝĂ
ĂƐLJŶĐŚƌŽŶŽƵƐƚŝĞƐƚŽĂŶŽƚŚĞƌ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶŵĂLJŝŶĐůƵĚĞŽƌĞdžĐůƵĚĞŵĞŐĂǁĂƚƚ
ƚƌĂŶƐĨĞƌƐŽŶƚŚŽƐĞdŝĞ>ŝŶĞƐŝŶƚŚĞŝƌĂĐƚƵĂůŝŶƚĞƌĐŚĂŶŐĞ͕ƉƌŽǀŝĚĞĚƚŚĞLJĂƌĞŝŵƉůĞŵĞŶƚĞĚ
ŝŶƚŚĞƐĂŵĞŵĂŶŶĞƌĨŽƌEĞƚ/ŶƚĞƌĐŚĂŶŐĞ^ĐŚĞĚƵůĞ͘
E/^;^ĐŚĞĚƵůĞĚEĞƚ/ŶƚĞƌĐŚĂŶŐĞͿŝƐƚŚĞĂůŐĞďƌĂŝĐƐƵŵŽĨĂůůƐĐŚĞĚƵůĞĚŵĞŐĂǁĂƚƚ
ƚƌĂŶƐĨĞƌƐ͕ŝŶĐůƵĚŝŶŐLJŶĂŵŝĐ^ĐŚĞĚƵůĞƐ͕ǁŝƚŚĂĚũĂĐĞŶƚĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐ͕ĂŶĚƚĂŬŝŶŐ
ŝŶƚŽĂĐĐŽƵŶƚƚŚĞĞĨĨĞĐƚƐŽĨƐĐŚĞĚƵůĞƌĂŵƉƐ͘ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐĚŝƌĞĐƚůLJĐŽŶŶĞĐƚĞĚǀŝĂ
ĂƐLJŶĐŚƌŽŶŽƵƐƚŝĞƐƚŽĂŶŽƚŚĞƌ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶŵĂLJŝŶĐůƵĚĞŽƌĞdžĐůƵĚĞŵĞŐĂǁĂƚƚ

>ͲϬϬϮͲϮ
:ƵůLJϮϬϭϯ



WĂŐĞϰŽĨϭϭ



^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮʹŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ
ĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
ƚƌĂŶƐĨĞƌƐŽŶƚŚŽƐĞdŝĞ>ŝŶĞƐŝŶƚŚĞŝƌƐĐŚĞĚƵůĞĚ/ŶƚĞƌĐŚĂŶŐĞ͕ƉƌŽǀŝĚĞĚƚŚĞLJĂƌĞ
ŝŵƉůĞŵĞŶƚĞĚŝŶƚŚĞƐĂŵĞŵĂŶŶĞƌĨŽƌEĞƚ/ŶƚĞƌĐŚĂŶŐĞĐƚƵĂů͘
;&ƌĞƋƵĞŶĐLJŝĂƐ^ĞƚƚŝŶŐͿŝƐƚŚĞ&ƌĞƋƵĞŶĐLJŝĂƐ^ĞƚƚŝŶŐ;ŝŶŶĞŐĂƚŝǀĞDtͬϬ͘ϭ,njͿĨŽƌƚŚĞ
ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͘
ϭϬŝƐƚŚĞĐŽŶƐƚĂŶƚĨĂĐƚŽƌƚŚĂƚĐŽŶǀĞƌƚƐƚŚĞ&ƌĞƋƵĞŶĐLJŝĂƐ^ĞƚƚŝŶŐƵŶŝƚƐƚŽDtͬ,nj͘
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&^;^ĐŚĞĚƵůĞĚ&ƌĞƋƵĞŶĐLJͿŝƐϲϬ͘Ϭ,nj͕ĞdžĐĞƉƚĚƵƌŝŶŐĂƚŝŵĞĐŽƌƌĞĐƚŝŽŶ͘
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ĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶƚŚĞŝŶƚĞŐƌĂƚĞĚŚŽƵƌůLJĂǀĞƌĂŐĞŽĨƚŚĞŶĞƚŝŶƚĞƌĐŚĂŶŐĞĂĐƚƵĂů;E/Ϳ
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on/off peak

IATEC

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accum

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ǁŚĞŶŽƉĞƌĂƚŝŶŐŝŶƵƚŽŵĂƚŝĐdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶĐŽŶƚƌŽůŵŽĚĞ͘

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•

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//ĂĐƚƵĂůŝƐƚŚĞŚŽƵƌůLJ/ŶĂĚǀĞƌƚĞŶƚ/ŶƚĞƌĐŚĂŶŐĞĨŽƌƚŚĞůĂƐƚŚŽƵƌ͘

•

ȴdŝƐƚŚĞŚŽƵƌůLJĐŚĂŶŐĞŝŶƐLJƐƚĞŵdŝŵĞƌƌŽƌĂƐĚŝƐƚƌŝďƵƚĞĚďLJƚŚĞ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ
dŝŵĞDŽŶŝƚŽƌ͘tŚĞƌĞ͗



ȴdсdĞŶĚŚŽƵƌʹdďĞŐŝŶŚŽƵƌʹdĂĚũʹ;ƚͿΎ;dŽĨĨƐĞƚͿ

•

dĂĚũŝƐƚŚĞZĞůŝĂďŝůŝƚLJŽŽƌĚŝŶĂƚŽƌĂĚũƵƐƚŵĞŶƚĨŽƌĚŝĨĨĞƌĞŶĐĞƐǁŝƚŚ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ
dŝŵĞDŽŶŝƚŽƌĐŽŶƚƌŽůĐĞŶƚĞƌĐůŽĐŬƐ͘

•

ƚŝƐƚŚĞŶƵŵďĞƌŽĨŵŝŶƵƚĞƐŽĨDĂŶƵĂůdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶƚŚĂƚŽĐĐƵƌƌĞĚĚƵƌŝŶŐƚŚĞ
ŚŽƵƌ͘

•

dŽĨĨƐĞƚŝƐϬ͘ϬϬϬŽƌнϬ͘ϬϮϬŽƌͲϬ͘ϬϮϬ͘

•

W//ĂĐĐƵŵŝƐƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛ƐĂĐĐƵŵƵůĂƚĞĚW//ŚŽƵƌůLJŝŶDtŚ͘ŶKŶͲWĞĂŬĂŶĚ
KĨĨͲWĞĂŬĂĐĐƵŵƵůĂƚŝŽŶĂĐĐŽƵŶƚŝŶŐŝƐƌĞƋƵŝƌĞĚ͘

>ͲϬϬϮͲϮ
:ƵůLJϮϬϭϯ



WĂŐĞϱŽĨϭϭ



^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮʹŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ
ĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
tŚĞƌĞ͗

PII

on/off peak
accum

сůĂƐƚƉĞƌŝŽĚ͛Ɛ

on/off peak

PII

accum

нW//ŚŽƵƌůLJ


ůůEZ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶƐǁŝƚŚŵƵůƚŝƉůĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐŽƉĞƌĂƚĞƵƐŝŶŐƚŚĞƉƌŝŶĐŝƉůĞƐ
ŽĨdŝĞͲůŝŶĞŝĂƐ;d>ͿŽŶƚƌŽůĂŶĚƌĞƋƵŝƌĞƚŚĞƵƐĞŽĨĂŶĞƋƵĂƚŝŽŶƐŝŵŝůĂƌƚŽƚŚĞ
ZĞƉŽƌƚŝŶŐĚĞĨŝŶĞĚĂďŽǀĞ͘ŶLJŵŽĚŝĨŝĐĂƚŝŽŶ;ƐͿƚŽƚŚŝƐƐƉĞĐŝĨŝĞĚZĞƉŽƌƚŝŶŐ
ĞƋƵĂƚŝŽŶƚŚĂƚŝƐ;ĂƌĞͿŝŵƉůĞŵĞŶƚĞĚĨŽƌĂůůƐŽŶĂŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶĂŶĚŝƐ;ĂƌĞͿĐŽŶƐŝƐƚĞŶƚ
ǁŝƚŚƚŚĞĨŽůůŽǁŝŶŐĨŽƵƌƉƌŝŶĐŝƉůĞƐǁŝůůƉƌŽǀŝĚĞĂǀĂůŝĚĂůƚĞƌŶĂƚŝǀĞZĞƉŽƌƚŝŶŐĞƋƵĂƚŝŽŶ
ĐŽŶƐŝƐƚĞŶƚǁŝƚŚƚŚĞŵĞĂƐƵƌĞƐŝŶĐůƵĚĞĚŝŶƚŚŝƐƐƚĂŶĚĂƌĚ͘



>ͲϬϬϮͲϮ
:ƵůLJϮϬϭϯ

ϭ͘ ůůƉŽƌƚŝŽŶƐŽĨƚŚĞ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶĂƌĞŝŶĐůƵĚĞĚŝŶŽŶĞĂƌĞĂŽƌĂŶŽƚŚĞƌƐŽƚŚĂƚ
ƚŚĞƐƵŵŽĨĂůůĂƌĞĂŐĞŶĞƌĂƚŝŽŶ͕ůŽĂĚƐĂŶĚůŽƐƐĞƐŝƐƚŚĞƐĂŵĞĂƐƚŽƚĂůƐLJƐƚĞŵ
ŐĞŶĞƌĂƚŝŽŶ͕ůŽĂĚĂŶĚůŽƐƐĞƐ͘
Ϯ͘ dŚĞĂůŐĞďƌĂŝĐƐƵŵŽĨĂůůĂƌĞĂEĞƚ/ŶƚĞƌĐŚĂŶŐĞ^ĐŚĞĚƵůĞƐĂŶĚĂůůEĞƚ/ŶƚĞƌĐŚĂŶŐĞ
ĂĐƚƵĂůǀĂůƵĞƐŝƐĞƋƵĂůƚŽnjĞƌŽĂƚĂůůƚŝŵĞƐ͘
ϯ͘ dŚĞƵƐĞŽĨĂĐŽŵŵŽŶ^ĐŚĞĚƵůĞĚ&ƌĞƋƵĞŶĐLJ&^ĨŽƌĂůůĂƌĞĂƐĂƚĂůůƚŝŵĞƐ͘
ϰ͘ dŚĞĂďƐĞŶĐĞŽĨŵĞƚĞƌŝŶŐŽƌĐŽŵƉƵƚĂƚŝŽŶĂůĞƌƌŽƌƐ͘;dŚĞŝŶĐůƵƐŝŽŶĂŶĚƵƐĞŽĨƚŚĞ
/DƚĞƌŵƚŽĂĐĐŽƵŶƚĨŽƌŬŶŽǁŶŵĞƚĞƌŝŶŐŽƌĐŽŵƉƵƚĂƚŝŽŶĂůĞƌƌŽƌƐ͘Ϳ




WĂŐĞϲŽĨϭϭ



^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮʹŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ
ĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
͘ /ŶƚƌŽĚƵĐƚŝŽŶ
ϭ͘

dŝƚůĞ͗ ŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ&ƌŽŵ
ĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ

Ϯ͘

EƵŵďĞƌ͗ >ͲϬϬϮͲϮ

ϯ͘

WƵƌƉŽƐĞ͗ dŽĞŶƐƵƌĞƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJŽƌZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉďĂůĂŶĐĞƐ
ƌĞƐŽƵƌĐĞƐĂŶĚĚĞŵĂŶĚĂŶĚƌĞƚƵƌŶƐƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛ƐŽƌZĞƐĞƌǀĞ^ŚĂƌŝŶŐ
'ƌŽƵƉ͛ƐƌĞĂŽŶƚƌŽůƌƌŽƌƚŽĚĞĨŝŶĞĚǀĂůƵĞƐ;ƐƵďũĞĐƚƚŽĂƉƉůŝĐĂďůĞůŝŵŝƚƐͿĨŽůůŽǁŝŶŐĂ
ZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͘

ϰ͘

ƉƉůŝĐĂďŝůŝƚLJ͗
ƉƉůŝĐĂďŝůŝƚLJŝƐĚĞƚĞƌŵŝŶĞĚŽŶĂŶŝŶĚŝǀŝĚƵĂůĞǀĞŶƚďĂƐŝƐ͕ďƵƚƚŚŝƐƐƚĂŶĚĂƌĚĚŽĞƐŶŽƚ
ĂƉƉůLJƚŽĂZĞƐƉŽŶƐŝďůĞŶƚŝƚLJĚƵƌŝŶŐƉĞƌŝŽĚƐǁŚĞŶƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJŝƐŝŶŶĞƌŐLJ
ŵĞƌŐĞŶĐLJůĞƌƚ>ĞǀĞůϮŽƌ>ĞǀĞůϯ͘
ϰ͘ϭ͘ ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ
ϰ͘ϭ͘ϭ ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJƚŚĂƚŝƐĂŵĞŵďĞƌŽĨĂZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉŝƐƚŚĞ
ZĞƐƉŽŶƐŝďůĞŶƚŝƚLJŽŶůLJŝŶƉĞƌŝŽĚƐĚƵƌŝŶŐǁŚŝĐŚƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJŝƐ
ŶŽƚŝŶĂĐƚŝǀĞƐƚĂƚƵƐƵŶĚĞƌƚŚĞĂƉƉůŝĐĂďůĞĂŐƌĞĞŵĞŶƚŽƌŐŽǀĞƌŶŝŶŐƌƵůĞƐĨŽƌ
ƚŚĞZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ͘
ϰ͘Ϯ͘ ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ

ϱ͘

;WƌŽƉŽƐĞĚͿĨĨĞĐƚŝǀĞĂƚĞ͗
ϱ͘ϭ͘ &ŝƌƐƚĚĂLJŽĨƚŚĞĨŝƌƐƚĐĂůĞŶĚĂƌƋƵĂƌƚĞƌƚŚĂƚŝƐƐŝdžŵŽŶƚŚƐďĞLJŽŶĚƚŚĞĚĂƚĞƚŚĂƚ
ƚŚŝƐƐƚĂŶĚĂƌĚŝƐĂƉƉƌŽǀĞĚďLJĂƉƉůŝĐĂďůĞƌĞŐƵůĂƚŽƌLJĂƵƚŚŽƌŝƚŝĞƐ͕ŽƌŝŶƚŚŽƐĞ
ũƵƌŝƐĚŝĐƚŝŽŶƐǁŚĞƌĞƌĞŐƵůĂƚŽƌLJĂƉƉƌŽǀĂůŝƐŶŽƚƌĞƋƵŝƌĞĚ͕ƚŚĞƐƚĂŶĚĂƌĚďĞĐŽŵĞƐ
ĞĨĨĞĐƚŝǀĞƚŚĞĨŝƌƐƚĚĂLJŽĨƚŚĞĨŝƌƐƚĐĂůĞŶĚĂƌƋƵĂƌƚĞƌƚŚĂƚŝƐƐŝdžŵŽŶƚŚƐďĞLJŽŶĚƚŚĞ
ĚĂƚĞƚŚŝƐƐƚĂŶĚĂƌĚŝƐĂƉƉƌŽǀĞĚďLJƚŚĞEZŽĂƌĚŽĨdƌƵƐƚĞĞƐ͕͛ŽƌĂƐŽƚŚĞƌǁŝƐĞ
ŵĂĚĞĞĨĨĞĐƚŝǀĞƉƵƌƐƵĂŶƚƚŽƚŚĞůĂǁƐĂƉƉůŝĐĂďůĞƚŽƐƵĐŚZKŐŽǀĞƌŶŵĞŶƚĂů
ĂƵƚŚŽƌŝƚŝĞƐ͘

͘ ZĞƋƵŝƌĞŵĞŶƚƐ
Zϭ͘

džĐĞƉƚǁŚĞŶĂŶŶĞƌŐLJŵĞƌŐĞŶĐLJůĞƌƚ>ĞǀĞůϮŽƌ>ĞǀĞůϯŝƐŝŶĞĨĨĞĐƚ͕ƚdŚĞ
ZĞƐƉŽŶƐŝďůĞŶƚŝƚLJĞdžƉĞƌŝĞŶĐŝŶŐĂZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐŚĂůů͕
ĚĞŵŽŶƐƚƌĂƚĞƚŚĂƚǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕ƚŚĞZĞƐƉŽŶƐŝďůĞ
ŶƚŝƚLJƌĞƚƵƌŶĞĚŝƚƐƚŽĂƚůĞĂƐƚ͗΀sŝŽůĂƚŝŽŶZŝƐŬ&ĂĐƚŽƌ͗DĞĚŝƵŵ΁΀dŝŵĞ,ŽƌŝnjŽŶ͗ZĞĂůͲ
ƚŝŵĞKƉĞƌĂƚŝŽŶƐ΁
•

ĞƌŽ͕;ŝĨŝƚƐWƌĞͲZĞƉŽƌƚŝŶŐĂďůĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞǁĂƐƉŽƐŝƚŝǀĞŽƌĞƋƵĂů
ƚŽnjĞƌŽͿ͗
o

>ͲϬϬϮͲϮ
:ƵůLJϮϬϭϯ

ůĞƐƐƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨĂůůƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJ
ǀĞŶƚƐƚŚĂƚŽĐĐƵƌƉƌŝŽƌƚŽƚŚĂƚǀĂůƵĞŽĨZĞƉŽƌƚŝŶŐǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJ
ǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕ĂŶĚ



WĂŐĞϳŽĨϭϭ



^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮʹŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ
ĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
o

&ƵƌƚŚĞƌƌĞĚƵĐĞĚďLJƚŚĞŵĂŐŶŝƚƵĚĞŽĨƚŚĞĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶ;ŝͿƚŚĞ
ZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛ƐDŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;D^^ͿĂŶĚ;ŝŝͿƚŚĞƐƵŵ
ŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚĂůů
ƉƌĞǀŝŽƵƐĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚŚĂǀĞŶŽƚĐŽŵƉůĞƚĞĚƚŚĞŝƌ
ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞǀĞŶƚZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚǁŚĞŶƚŚĞƐƵŵƌĞĨĞƌĞŶĐĞĚŝŶ
ĐůĂƵƐĞ;ŝŝͿŽĨƚŚŝƐďƵůůĞƚŝƐŐƌĞĂƚĞƌƚŚĂŶD^^͕

Kƌ͕
•

/ƚƐWƌĞͲZĞƉŽƌƚŝŶŐĂďůĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞ͕;ŝĨŝƚƐWƌĞͲZĞƉŽƌƚŝŶŐĂďůĞ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞǁĂƐŶĞŐĂƚŝǀĞͿ͕
o ůĞƐƐƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨĂůůƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJ
ǀĞŶƚƐƚŚĂƚŽĐĐƵƌƉƌŝŽƌƚŽƚŚĂƚǀĂůƵĞŽĨZĞƉŽƌƚŝŶŐǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJ
ǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕ĂŶĚ
o &ƵƌƚŚĞƌƌĞĚƵĐĞĚďLJƚŚĞŵĂŐŶŝƚƵĚĞŽĨƚŚĞĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶ;ŝͿƚŚĞ
ZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛ƐDŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;D^^ͿĂŶĚ;ŝŝͿƚŚĞƐƵŵ
ŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚĂůů
ƉƌĞǀŝŽƵƐĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚŚĂǀĞŶŽƚĐŽŵƉůĞƚĞĚƚŚĞŝƌ
ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞǀĞŶƚZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚǁŚĞŶƚŚĞƐƵŵƌĞĨĞƌĞŶĐĞĚŝŶ
ĐůĂƵƐĞ;ŝŝͿŽĨƚŚŝƐďƵůůĞƚŝƐŐƌĞĂƚĞƌƚŚĂŶD^^͘

ϭ͘ϭ͘ dŚĞƌĞƋƵŝƌĞĚƌĞƉŽƌƚŝŶŐĨŽƌŵŝƐZ&Žƌŵϭ͘
ϭ͘Ϯ͘ dŚŝƐƌĞƋƵŝƌĞŵĞŶƚ;ŝŶŝƚƐĞŶƚŝƌĞƚLJͿĚŽĞƐŶŽƚĂƉƉůLJǁŚĞŶƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ
ĞdžƉĞƌŝĞŶĐŝŶŐĂZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚŝƐĞdžƉĞƌŝĞŶĐŝŶŐĂŶ
ŶĞƌŐLJŵĞƌŐĞŶĐLJůĞƌƚ>ĞǀĞůϮŽƌ>ĞǀĞůϯ͘
ZϮ͘

džĐĞƉƚĚƵƌŝŶŐƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛ƐŽŶƚŝŶŐĞŶĐLJǀĞŶƚŝƐƚƵƌďĂŶĐĞZĞĐŽǀĞƌLJWĞƌŝŽĚ
ĂŶĚƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛ƐŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞZĞƐƚŽƌĂƚŝŽŶZĞĐŽǀĞƌLJWĞƌŝŽĚ͕Žƌ
ĚƵƌŝŶŐĂŶŶĞƌŐLJŵĞƌŐĞŶĐLJůĞƌƚ>ĞǀĞůϮŽƌϯĨŽƌƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJĂŶĚĨŽƌĂŶ
ĂĚĚŝƚŝŽŶĂůĨŝǀĞŚŽƵƌƐĚƵƌŝŶŐĂŐŝǀĞŶĐĂůĞŶĚĂƌƋƵĂƌƚĞƌ͕ƚŚĞĞĂĐŚZĞƐƉŽŶƐŝďůĞŶƚŝƚLJƐŚĂůů
ŵĂŝŶƚĂŝŶĂŶĂŵŽƵŶƚŽĨŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĂƚůĞĂƐƚĞƋƵĂůƚŽŝƚƐDŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞ
ŽŶƚŝŶŐĞŶĐLJ͘΀sŝŽůĂƚŝŽŶZŝƐŬ&ĂĐƚŽƌ͗DĞĚŝƵŵ΁΀dŝŵĞ,ŽƌŝnjŽŶ͗ZĞĂůͲƚŝŵĞKƉĞƌĂƚŝŽŶƐ΁


͘ DĞĂƐƵƌĞƐ
Dϭ͘

ĂĐŚZĞƐƉŽŶƐŝďůĞŶƚŝƚLJƐŚĂůůŚĂǀĞ͕ĂŶĚƉƌŽǀŝĚĞƵƉŽŶƌĞƋƵĞƐƚ͕ĂƐĞǀŝĚĞŶĐĞ͕ĂZ
&ŽƌŵϭǁŝƚŚĚĂƚĞĂŶĚƚŝŵĞŽĨŽĐĐƵƌƌĞŶĐĞƚŽƐŚŽǁĐŽŵƉůŝĂŶĐĞǁŝƚŚZĞƋƵŝƌĞŵĞŶƚZϭ
ĂŶĚ͕ŝŶĐůƵĚŝŶŐĂĚĚŝƚŝŽŶĂůĚŽĐƵŵĞŶƚĂƚŝŽŶŽĨŽŶĂŶLJĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƚŚĂƚ
ŚĂƐŶŽƚĐŽŵƉůĞƚĞĚŝƚƐŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚĂŶĚƚŚĂƚŝƐƵƐĞĚƚŽ
ƌĞĚƵĐĞƚŚĞƌĞĐŽǀĞƌLJƚŽƚŚĞĂŵŽƵŶƚůŝŵŝƚĞĚďLJD^^͘

DϮ.

ĂĐŚZĞƐƉŽŶƐŝďůĞŶƚŝƚLJƐŚĂůůŚĂǀĞĚĂƚĞĚĚŽĐƵŵĞŶƚĂƚŝŽŶƚŚĂƚĚĞŵŽŶƐƚƌĂƚĞƐŝƚƐ
ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ͕ĂǀĞƌĂŐĞĚŽǀĞƌĞĂĐŚůŽĐŬ,ŽƵƌ͕ǁĂƐŵĂŝŶƚĂŝŶĞĚŝŶĂĐĐŽƌĚĂŶĐĞ
ǁŝƚŚƚŚĞĂŵŽƵŶƚƐŝĚĞŶƚŝĨŝĞĚŝŶZĞƋƵŝƌĞŵĞŶƚZϮĞdžĐĞƉƚǁŝƚŚŝŶƚŚĞĨŝƌƐƚϭϬϱŵŝŶƵƚĞƐ
ĨŽůůŽǁŝŶŐĂŶĞǀĞŶƚƌĞƋƵŝƌŝŶŐƚŚĞĂĐƚŝǀĂƚŝŽŶŽĨŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ͘

>ͲϬϬϮͲϮ
:ƵůLJϮϬϭϯ



WĂŐĞϴŽĨϭϭ



^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮʹŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ
ĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ


͘ ŽŵƉůŝĂŶĐĞ
ϭ͘

ŽŵƉůŝĂŶĐĞDŽŶŝƚŽƌŝŶŐWƌŽĐĞƐƐ
ϭ͘ϭ͘ ŽŵƉůŝĂŶĐĞŶĨŽƌĐĞŵĞŶƚƵƚŚŽƌŝƚLJ
ƐĚĞĨŝŶĞĚŝŶƚŚĞEZZƵůĞƐŽĨWƌŽĐĞĚƵƌĞ͕͞ŽŵƉůŝĂŶĐĞŶĨŽƌĐĞŵĞŶƚƵƚŚŽƌŝƚLJ͟
ŵĞĂŶƐEZŽƌƚŚĞZĞŐŝŽŶĂůŶƚŝƚLJŝŶƚŚĞŝƌƌĞƐƉĞĐƚŝǀĞƌŽůĞƐŽĨŵŽŶŝƚŽƌŝŶŐĂŶĚ
ĞŶĨŽƌĐŝŶŐĐŽŵƉůŝĂŶĐĞǁŝƚŚƚŚĞEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚƐ͘
ϭ͘Ϯ͘ ĂƚĂZĞƚĞŶƚŝŽŶ
dŚĞĨŽůůŽǁŝŶŐĞǀŝĚĞŶĐĞƌĞƚĞŶƚŝŽŶƉĞƌŝŽĚƐŝĚĞŶƚŝĨLJƚŚĞƉĞƌŝŽĚŽĨƚŝŵĞĂŶĞŶƚŝƚLJŝƐ
ƌĞƋƵŝƌĞĚƚŽƌĞƚĂŝŶƐƉĞĐŝĨŝĐĞǀŝĚĞŶĐĞƚŽĚĞŵŽŶƐƚƌĂƚĞĐŽŵƉůŝĂŶĐĞ͘&ŽƌŝŶƐƚĂŶĐĞƐ
ǁŚĞƌĞƚŚĞĞǀŝĚĞŶĐĞƌĞƚĞŶƚŝŽŶƉĞƌŝŽĚƐƉĞĐŝĨŝĞĚďĞůŽǁŝƐƐŚŽƌƚĞƌƚŚĂŶƚŚĞƚŝŵĞ
ƐŝŶĐĞƚŚĞůĂƐƚĂƵĚŝƚ͕ƚŚĞŽŵƉůŝĂŶĐĞŶĨŽƌĐĞŵĞŶƚƵƚŚŽƌŝƚLJŵĂLJĂƐŬĂŶĞŶƚŝƚLJƚŽ
ƉƌŽǀŝĚĞŽƚŚĞƌĞǀŝĚĞŶĐĞƚŽƐŚŽǁƚŚĂƚŝƚǁĂƐĐŽŵƉůŝĂŶƚĨŽƌƚŚĞĨƵůůͲƚŝŵĞƉĞƌŝŽĚ
ƐŝŶĐĞƚŚĞůĂƐƚĂƵĚŝƚ͘
dŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJƐŚĂůůƌĞƚĂŝŶĚĂƚĂŽƌĞǀŝĚĞŶĐĞƚŽƐŚŽǁĐŽŵƉůŝĂŶĐĞĨŽƌƚŚĞ
ĐƵƌƌĞŶƚLJĞĂƌ͕ƉůƵƐƚŚƌĞĞƉƌĞǀŝŽƵƐĐĂůĞŶĚĂƌLJĞĂƌƐ͕ƵŶůĞƐƐĚŝƌĞĐƚĞĚďLJŝƚƐ
ŽŵƉůŝĂŶĐĞŶĨŽƌĐĞŵĞŶƚƵƚŚŽƌŝƚLJƚŽƌĞƚĂŝŶƐƉĞĐŝĨŝĐĞǀŝĚĞŶĐĞĨŽƌĂůŽŶŐĞƌ
ƉĞƌŝŽĚŽĨƚŝŵĞĂƐƉĂƌƚŽĨĂŶŝŶǀĞƐƚŝŐĂƚŝŽŶ͘
/ĨĂZĞƐƉŽŶƐŝďůĞŶƚŝƚLJŝƐĨŽƵŶĚŶŽŶĐŽŵƉůŝĂŶƚ͕ŝƚƐŚĂůůŬĞĞƉŝŶĨŽƌŵĂƚŝŽŶƌĞůĂƚĞĚƚŽ
ƚŚĞŶŽŶĐŽŵƉůŝĂŶĐĞƵŶƚŝůĨŽƵŶĚĐŽŵƉůŝĂŶƚ͕ŽƌĨŽƌƚŚĞƚŝŵĞƉĞƌŝŽĚƐƉĞĐŝĨŝĞĚĂďŽǀĞ͕
ǁŚŝĐŚĞǀĞƌŝƐůŽŶŐĞƌ͘
dŚĞŽŵƉůŝĂŶĐĞŶĨŽƌĐĞŵĞŶƚƵƚŚŽƌŝƚLJƐŚĂůůŬĞĞƉƚŚĞůĂƐƚĂƵĚŝƚƌĞĐŽƌĚƐĂŶĚĂůů
ƐƵďƐĞƋƵĞŶƚƌĞƋƵĞƐƚĞĚĂŶĚƐƵďŵŝƚƚĞĚƌĞĐŽƌĚƐ͘
ϭ͘ϯ͘ ŽŵƉůŝĂŶĐĞDŽŶŝƚŽƌŝŶŐĂŶĚƐƐĞƐƐŵĞŶƚWƌŽĐĞƐƐĞƐ
ŽŵƉůŝĂŶĐĞƵĚŝƚƐ
^ĞůĨͲĞƌƚŝĨŝĐĂƚŝŽŶƐ
^ƉŽƚŚĞĐŬŝŶŐ
ŽŵƉůŝĂŶĐĞ/ŶǀĞƐƚŝŐĂƚŝŽŶƐ
^ĞůĨͲZĞƉŽƌƚŝŶŐ
ŽŵƉůĂŝŶƚƐ
ϭ͘ϰ͘ ĚĚŝƚŝŽŶĂůŽŵƉůŝĂŶĐĞ/ŶĨŽƌŵĂƚŝŽŶ
dŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJŵĂLJƵƐĞŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌĂŶLJĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚĂƐƌĞƋƵŝƌĞĚĨŽƌĂŶLJŽƚŚĞƌĂƉƉůŝĐĂďůĞƐƚĂŶĚĂƌĚƐ͘

>ͲϬϬϮͲϮ
:ƵůLJϮϬϭϯ



WĂŐĞϵŽĨϭϭ



^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮʹŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ
ĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
ZĞƐƉŽŶƐŝďůĞŶƚŝƚLJŝƐŶŽƚƐƵďũĞĐƚƚŽĐŽŵƉůŝĂŶĐĞǁŝƚŚƚŚŝƐƐƚĂŶĚĂƌĚŝŶĂŶLJƉĞƌŝŽĚ
ĚƵƌŝŶŐǁŚŝĐŚƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJŝƐŝŶĂŶŶĞƌŐLJŵĞƌŐĞŶĐLJůĞƌƚ>ĞǀĞůϮŽƌ
>ĞǀĞůϯ͘

Ϯ͘

sŝŽůĂƚŝŽŶ^ĞǀĞƌŝƚLJ>ĞǀĞůƐ
Zη

>ŽǁĞƌs^>

DŽĚĞƌĂƚĞs^>

,ŝŐŚs^>

^ĞǀĞƌĞs^>

Zϭ

dŚĞZĞƐƉŽŶƐŝďůĞ
ŶƚŝƚLJƌĞĐŽǀĞƌĞĚ
ƉĂƌƚŝĂůůLJĨƌŽŵĂ
ZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJ
ǀĞŶƚĚƵƌŝŶŐƚŚĞ
ŽŶƚŝŶŐĞŶĐLJ
ǀĞŶƚZĞĐŽǀĞƌLJ
WĞƌŝŽĚďƵƚ
ƌĞĐŽǀĞƌĞĚůĞƐƐ
ƚŚĂŶϭϬϬйďƵƚ
ŵŽƌĞƚŚĂŶϵϬй
ŽĨƌĞƋƵŝƌĞĚ
ƌĞĐŽǀĞƌLJ͘

dŚĞZĞƐƉŽŶƐŝďůĞ
ŶƚŝƚLJƌĞĐŽǀĞƌĞĚ
ƉĂƌƚŝĂůůLJĨƌŽŵĂ
ZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJ
ǀĞŶƚĚƵƌŝŶŐƚŚĞ
ŽŶƚŝŶŐĞŶĐLJ
ǀĞŶƚZĞĐŽǀĞƌLJ
WĞƌŝŽĚďƵƚ
ƌĞĐŽǀĞƌĞĚϵϬйŽƌ
ůĞƐƐďƵƚŵŽƌĞ
ƚŚĂŶϴϬйŽĨ
ƌĞƋƵŝƌĞĚ
ƌĞĐŽǀĞƌLJ͘

dŚĞZĞƐƉŽŶƐŝďůĞ
ŶƚŝƚLJƌĞĐŽǀĞƌĞĚ
ƉĂƌƚŝĂůůLJĨƌŽŵĂ
ZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJ
ǀĞŶƚĚƵƌŝŶŐƚŚĞ
ŽŶƚŝŶŐĞŶĐLJ
ǀĞŶƚZĞĐŽǀĞƌLJ
WĞƌŝŽĚďƵƚ
ƌĞĐŽǀĞƌĞĚϴϬйŽƌ
ůĞƐƐďƵƚŵŽƌĞ
ƚŚĂŶϳϬйŽĨ
ƌĞƋƵŝƌĞĚ
ƌĞĐŽǀĞƌLJ͘

dŚĞZĞƐƉŽŶƐŝďůĞ
ŶƚŝƚLJƌĞĐŽǀĞƌĞĚ
ƉĂƌƚŝĂůůLJĨƌŽŵĂ
ZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJ
ǀĞŶƚĚƵƌŝŶŐƚŚĞ
ŽŶƚŝŶŐĞŶĐLJ
ǀĞŶƚZĞĐŽǀĞƌLJ
WĞƌŝŽĚďƵƚ
ƌĞĐŽǀĞƌĞĚϳϬйŽƌ
ůĞƐƐŽĨƌĞƋƵŝƌĞĚ
ƌĞĐŽǀĞƌLJ͘

ZϮ

/ŶĞĂĐŚĐĂůĞŶĚĂƌ
ƋƵĂƌƚĞƌ͕ƚŚĞ
ZĞƐƉŽŶƐŝďůĞ
ŶƚŝƚLJŚĂĚ
ŽŶƚŝŶŐĞŶĐLJ
ZĞƐĞƌǀĞƐďƵƚŝƚƐ
ŽŶƚŝŶŐĞŶĐLJ
ZĞƐĞƌǀĞǁĂƐ
ĚĞĨŝĐŝĞŶƚĨŽƌ
ŵŽƌĞƚŚĂŶϱ
ŚŽƵƌƐďƵƚůĞƐƐ
ƚŚĂŶŽƌĞƋƵĂůƚŽ
ϭϱŚŽƵƌƐ͘

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ƋƵĂƌƚĞƌ͕ƚŚĞ
ZĞƐƉŽŶƐŝďůĞ
ŶƚŝƚLJŚĂĚ
ŽŶƚŝŶŐĞŶĐLJ
ZĞƐĞƌǀĞƐďƵƚŝƚƐ
ŽŶƚŝŶŐĞŶĐLJ
ZĞƐĞƌǀĞǁĂƐ
ĚĞĨŝĐŝĞŶƚĨŽƌ
ŵŽƌĞƚŚĂŶϭϱ
ŚŽƵƌƐďƵƚůĞƐƐ
ƚŚĂŶŽƌĞƋƵĂůƚŽ
ϮϱŚŽƵƌƐ͘

/ŶĞĂĐŚĐĂůĞŶĚĂƌ
ƋƵĂƌƚĞƌ͕ƚŚĞ
ZĞƐƉŽŶƐŝďůĞ
ŶƚŝƚLJŚĂĚ
ŽŶƚŝŶŐĞŶĐLJ
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ŽŶƚŝŶŐĞŶĐLJ
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ĚĞĨŝĐŝĞŶƚĨŽƌ
ŵŽƌĞƚŚĂŶϮϱ
ŚŽƵƌƐďƵƚůĞƐƐ
ƚŚĂŶŽƌĞƋƵĂůƚŽ
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ƋƵĂƌƚĞƌ͕ƚŚĞ
ZĞƐƉŽŶƐŝďůĞ
ŶƚŝƚLJŚĂĚ
ŽŶƚŝŶŐĞŶĐLJ
ZĞƐĞƌǀĞƐďƵƚŝƚƐ
ŽŶƚŝŶŐĞŶĐLJ
ZĞƐĞƌǀĞǁĂƐ
ĚĞĨŝĐŝĞŶƚĨŽƌ
ŵŽƌĞƚŚĂŶϯϱ
ŚŽƵƌƐ͘


͘ ZĞŐŝŽŶĂůsĂƌŝĂŶĐĞƐ
EŽŶĞ͘
&͘ ƐƐŽĐŝĂƚĞĚŽĐƵŵĞŶƚƐ

>ͲϬϬϮͲϮ
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ĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
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ĐƚŝŽŶ

ŚĂŶŐĞdƌĂĐŬŝŶŐ

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ĨĨĞĐƚŝǀĞĂƚĞ

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ZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ

ƉƉƌŽǀĂůƐZĞƋƵŝƌĞĚ
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ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ

WƌĞƌĞƋƵŝƐŝƚĞƉƉƌŽǀĂůƐ
EŽŶĞ

ZĞǀŝƐŝŽŶƐƚŽ'ůŽƐƐĂƌLJdĞƌŵƐ
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ĂŶLJƐĞƌŝĞƐŽĨƐƵĐŚŽƚŚĞƌǁŝƐĞƐŝŶŐůĞĞǀĞŶƚƐ͕ǁŝƚŚĞĂĐŚƐĞƉĂƌĂƚĞĚĨƌŽŵƚŚĞŶĞdžƚďLJůĞƐƐƚŚĂŶŽŶĞ
ŵŝŶƵƚĞ͘
͘ ^ƵĚĚĞŶ>ŽƐƐŽĨŐĞŶĞƌĂƚŝŽŶ͗
Ă͘ ƵĞƚŽ
ŝ͘ hŶŝƚƚƌŝƉƉŝŶŐ͕
ŝŝ͘ >ŽƐƐŽĨŐĞŶĞƌĂƚŽƌ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ&ĂĐŝůŝƚLJƌĞƐƵůƚŝŶŐŝŶŝƐŽůĂƚŝŽŶŽĨƚŚĞ
ŐĞŶĞƌĂƚŽƌĨƌŽŵƚŚĞƵůŬůĞĐƚƌŝĐ^LJƐƚĞŵŽƌĨƌŽŵƚŚĞƌĞƐƉŽŶƐŝďůĞĞŶƚŝƚLJ͛Ɛ
ĞůĞĐƚƌŝĐƐLJƐƚĞŵ͕Žƌ
ŝŝŝ͘ ^ƵĚĚĞŶƵŶƉůĂŶŶĞĚŽƵƚĂŐĞŽĨƚƌĂŶƐŵŝƐƐŝŽŶ&ĂĐŝůŝƚLJ͖
ď͘ ŶĚ͕ƚŚĂƚĐĂƵƐĞƐĂŶƵŶĞdžƉĞĐƚĞĚĐŚĂŶŐĞƚŽƚŚĞƌĞƐƉŽŶƐŝďůĞĞŶƚŝƚLJ͛Ɛ͖
͘ ^ƵĚĚĞŶůŽƐƐŽĨĂŶ/ŵƉŽƌƚ͕ ĚƵĞƚŽĨŽƌĐĞĚŽƵƚĂŐĞŽĨƚƌĂŶƐŵŝƐƐŝŽŶĞƋƵŝƉŵĞŶƚƚŚĂƚĐĂƵƐĞƐĂŶ
ƵŶĞdžƉĞĐƚĞĚŝŵďĂůĂŶĐĞďĞƚǁĞĞŶŐĞŶĞƌĂƚŝŽŶĂŶĚůŽĂĚŽŶƚŚĞ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͘
C. ^ƵĚĚĞŶƌĞƐƚŽƌĂƚŝŽŶŽĨĂůŽĂĚƚŚĂƚǁĂƐƵƐĞĚĂƐĂƌĞƐŽƵƌĐĞƚŚĂƚĐĂƵƐĞƐĂŶƵŶĞdžƉĞĐƚĞĚĐŚĂŶŐĞ
ƚŽƚŚĞƌĞƐƉŽŶƐŝďůĞĞŶƚŝƚLJ͛Ɛ͘

DŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;D^^Ϳ͗dŚĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͕ĚƵĞƚŽĂƐŝŶŐůĞ
ĐŽŶƚŝŶŐĞŶĐLJ͕ƚŚĂƚǁŽƵůĚƌĞƐƵůƚŝŶƚŚĞŐƌĞĂƚĞƐƚůŽƐƐ;ŵĞĂƐƵƌĞĚŝŶDtͿŽĨƌĞƐŽƵƌĐĞŽƵƚƉƵƚƵƐĞĚďLJ
ƚŚĞZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ;Z^'ͿŽƌĂĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJƚŚĂƚŝƐŶŽƚƉĂƌƚŝĐŝƉĂƚŝŶŐĂƐĂŵĞŵďĞƌŽĨĂ
Z^'ĂƚƚŚĞƚŝŵĞŽĨƚŚĞĞǀĞŶƚƚŽŵĞĞƚĨŝƌŵƐLJƐƚĞŵůŽĂĚĂŶĚĞdžƉŽƌƚŽďůŝŐĂƚŝŽŶ;ĞdžĐůƵĚŝŶŐĞdžƉŽƌƚ
ŽďůŝŐĂƚŝŽŶĨŽƌǁŚŝĐŚŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞŽďůŝŐĂƚŝŽŶƐĂƌĞďĞŝŶŐŵĞƚďLJƚŚĞƐŝŶŬĂůĂŶĐŝŶŐ
ƵƚŚŽƌŝƚLJͿ͘
ZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͗ŶLJĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƌĞƐƵůƚŝŶŐŝŶĂůŽƐƐŽĨ
DtŽƵƚƉƵƚŐƌĞĂƚĞƌƚŚĂŶŽƌĞƋƵĂůƚŽƚŚĞůĞƐƐĞƌĂŵŽƵŶƚŽĨϴϬƉĞƌĐĞŶƚŽĨƚŚĞDŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞ
ŽŶƚŝŶŐĞŶĐLJ͕ŽƌƚŚĞĂŵŽƵŶƚůŝƐƚĞĚďĞůŽǁĨŽƌƚŚĞĂƉƉůŝĐĂďůĞ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶĂŶĚŽĐĐƵƌƌŝŶŐǁŝƚŚŝŶĂ
ƌŽůůŝŶŐŽŶĞͲŵŝŶƵƚĞŝŶƚĞƌǀĂůďĂƐĞĚŽŶD^ƐĐĂŶƌĂƚĞĚĂƚĂ͘dŚĞϴϬйƚŚƌĞƐŚŽůĚŵĂLJďĞƌĞĚƵĐĞĚƵƉŽŶ
ǁƌŝƚƚĞŶŶŽƚŝĨŝĐĂƚŝŽŶƚŽƚŚĞZĞŐŝŽŶĂůŶƚŝƚLJ͘
•

ĂƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶʹϵϬϬDt

•

tĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶʹϱϬϬDt

•

ZKdʹϴϬϬDt

•

YƵĞďĞĐʹϱϬϬDt

ŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͗ƉĞƌŝŽĚďĞŐŝŶŶŝŶŐĂƚƚŚĞƚŝŵĞƚŚĂƚƚŚĞƌĞƐŽƵƌĐĞŽƵƚƉƵƚ
ďĞŐŝŶƐƚŽĚĞĐůŝŶĞǁŝƚŚŝŶƚŚĞĨŝƌƐƚŽŶĞͲŵŝŶƵƚĞŝŶƚĞƌǀĂůƚŚĂƚĚĞĨŝŶĞƐĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͕
ĂŶĚĞdžƚĞŶĚƐĨŽƌĨŝĨƚĞĞŶŵŝŶƵƚĞƐƚŚĞƌĞĂĨƚĞƌ͘
ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚ͗ƉĞƌŝŽĚŶŽƚĞdžĐĞĞĚŝŶŐϵϬŵŝŶƵƚĞƐĨŽůůŽǁŝŶŐƚŚĞĞŶĚŽĨ
ƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͘

WƌĞͲZĞƉŽƌƚŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞ͗dŚĞĂǀĞƌĂŐĞǀĂůƵĞŽĨZĞƉŽƌƚŝŶŐ͕ŽƌZĞƐĞƌǀĞ
^ŚĂƌŝŶŐ'ƌŽƵƉZĞƉŽƌƚŝŶŐǁŚĞŶĂƉƉůŝĐĂďůĞ͕ŝŶƚŚĞϭϲƐĞĐŽŶĚŝŶƚĞƌǀĂůŝŵŵĞĚŝĂƚĞůLJƉƌŝŽƌƚŽƚŚĞ
ƐƚĂƌƚŽĨƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚďĂƐĞĚŽŶD^ƐĐĂŶƌĂƚĞĚĂƚĂ͘

ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉZĞƉŽƌƚŝŶŐ͗ƚĂŶLJŐŝǀĞŶƚŝŵĞŽĨŵĞĂƐƵƌĞŵĞŶƚĨŽƌƚŚĞĂƉƉůŝĐĂďůĞ
ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ͕ƚŚĞĂůŐĞďƌĂŝĐƐƵŵŽĨƚŚĞƐ;ŽƌĞƋƵŝǀĂůĞŶƚĂƐĐĂůĐƵůĂƚĞĚĂƚƐƵĐŚƚŝŵĞŽĨ
ŵĞĂƐƵƌĞŵĞŶƚͿŽĨƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐƉĂƌƚŝĐŝƉĂƚŝŶŐŝŶƚŚĞZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉĂƚƚŚĞƚŝŵĞ
ŽĨŵĞĂƐƵƌĞŵĞŶƚ͘

ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ͗dŚĞƉƌŽǀŝƐŝŽŶŽĨĐĂƉĂĐŝƚLJƚŚĂƚŵĂLJďĞĚĞƉůŽLJĞĚďLJƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJƚŽ
ƌĞƐƉŽŶĚƚŽĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚŽƚŚĞƌĐŽŶƚŝŶŐĞŶĐLJƌĞƋƵŝƌĞŵĞŶƚƐ;ƐƵĐŚĂƐŶĞƌŐLJ
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^ŝĚĞDĂŶĂŐĞŵĞŶƚ;^DͿ͕/ŶƚĞƌƌƵƉƚŝďůĞ>ŽĂĚĂŶĚƵŶůŽĂĚĞĚŐĞŶĞƌĂƚŝŽŶ͘
ZĞƉŽƌƚŝŶŐ͗dŚĞƐĐĂŶƌĂƚĞǀĂůƵĞƐŽĨĂĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛ƐƌĞĂŽŶƚƌŽůƌƌŽƌ;ͿŵĞĂƐƵƌĞĚ
ŝŶDt͕ǁŚŝĐŚŝŶĐůƵĚĞƐƚŚĞĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛ƐEĞƚĐƚƵĂů/ŶƚĞƌĐŚĂŶŐĞ

>ͲϬϬϮͲϮʹŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ

Ϯ

ĂŶĚŝƚƐEĞƚ^ĐŚĞĚƵůĞĚ/ŶƚĞƌĐŚĂŶŐĞ͕ƉůƵƐŝƚƐ&ƌĞƋƵĞŶĐLJŝĂƐŽďůŝŐĂƚŝŽŶ͕ƉůƵƐĂŶLJŬŶŽǁŶŵĞƚĞƌĞƌƌŽƌ͘
/ŶƚŚĞtĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͕ZĞƉŽƌƚŝŶŐŝŶĐůƵĚĞƐƵƚŽŵĂƚŝĐdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶ;dͿ͘
ZĞƉŽƌƚŝŶŐŝƐĐĂůĐƵůĂƚĞĚĂƐĨŽůůŽǁƐ͗

ZĞƉŽƌƚŝŶŐс;E/оE/^ͿоϭϬ;&о&^Ϳо/D
ZĞƉŽƌƚŝŶŐŝƐĐĂůĐƵůĂƚĞĚŝŶƚŚĞtĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶĂƐĨŽůůŽǁƐ͗

ZĞƉŽƌƚŝŶŐс;E/оE/^ͿоϭϬ;&о&^Ϳо/Dн/d
tŚĞƌĞ͗
E/;ĐƚƵĂůEĞƚ/ŶƚĞƌĐŚĂŶŐĞͿŝƐƚŚĞĂůŐĞďƌĂŝĐƐƵŵŽĨĂĐƚƵĂůŵĞŐĂǁĂƚƚƚƌĂŶƐĨĞƌƐĂĐƌŽƐƐĂůůdŝĞ
>ŝŶĞƐĂŶĚŝŶĐůƵĚĞƐWƐĞƵĚŽͲdŝĞƐ͘ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐĚŝƌĞĐƚůLJĐŽŶŶĞĐƚĞĚǀŝĂĂƐLJŶĐŚƌŽŶŽƵƐ
ƚŝĞƐƚŽĂŶŽƚŚĞƌ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶŵĂLJŝŶĐůƵĚĞŽƌĞdžĐůƵĚĞŵĞŐĂǁĂƚƚƚƌĂŶƐĨĞƌƐŽŶƚŚŽƐĞdŝĞ
>ŝŶĞƐŝŶƚŚĞŝƌĂĐƚƵĂůŝŶƚĞƌĐŚĂŶŐĞ͕ƉƌŽǀŝĚĞĚƚŚĞLJĂƌĞŝŵƉůĞŵĞŶƚĞĚŝŶƚŚĞƐĂŵĞŵĂŶŶĞƌĨŽƌ
EĞƚ/ŶƚĞƌĐŚĂŶŐĞ^ĐŚĞĚƵůĞ͘
E/^;^ĐŚĞĚƵůĞĚEĞƚ/ŶƚĞƌĐŚĂŶŐĞͿŝƐƚŚĞĂůŐĞďƌĂŝĐƐƵŵŽĨĂůůƐĐŚĞĚƵůĞĚŵĞŐĂǁĂƚƚƚƌĂŶƐĨĞƌƐ͕
ŝŶĐůƵĚŝŶŐLJŶĂŵŝĐ^ĐŚĞĚƵůĞƐ͕ǁŝƚŚĂĚũĂĐĞŶƚĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐ͕ĂŶĚƚĂŬŝŶŐŝŶƚŽĂĐĐŽƵŶƚ
ƚŚĞĞĨĨĞĐƚƐŽĨƐĐŚĞĚƵůĞƌĂŵƉƐ͘ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐĚŝƌĞĐƚůLJĐŽŶŶĞĐƚĞĚǀŝĂĂƐLJŶĐŚƌŽŶŽƵƐ
ƚŝĞƐƚŽĂŶŽƚŚĞƌ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶŵĂLJŝŶĐůƵĚĞŽƌĞdžĐůƵĚĞŵĞŐĂǁĂƚƚƚƌĂŶƐĨĞƌƐŽŶƚŚŽƐĞdŝĞ
>ŝŶĞƐŝŶƚŚĞŝƌƐĐŚĞĚƵůĞĚ/ŶƚĞƌĐŚĂŶŐĞ͕ƉƌŽǀŝĚĞĚƚŚĞLJĂƌĞŝŵƉůĞŵĞŶƚĞĚŝŶƚŚĞƐĂŵĞŵĂŶŶĞƌ
ĨŽƌEĞƚ/ŶƚĞƌĐŚĂŶŐĞĐƚƵĂů͘
;&ƌĞƋƵĞŶĐLJŝĂƐ^ĞƚƚŝŶŐͿŝƐƚŚĞ&ƌĞƋƵĞŶĐLJŝĂƐ^ĞƚƚŝŶŐ;ŝŶŶĞŐĂƚŝǀĞDtͬϬ͘ϭ,njͿĨŽƌƚŚĞ
ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͘
ϭϬŝƐƚŚĞĐŽŶƐƚĂŶƚĨĂĐƚŽƌƚŚĂƚĐŽŶǀĞƌƚƐƚŚĞ&ƌĞƋƵĞŶĐLJŝĂƐ^ĞƚƚŝŶŐƵŶŝƚƐƚŽDtͬ,nj͘
&;ĐƚƵĂů&ƌĞƋƵĞŶĐLJͿŝƐƚŚĞŵĞĂƐƵƌĞĚĨƌĞƋƵĞŶĐLJŝŶ,nj͘
&^;^ĐŚĞĚƵůĞĚ&ƌĞƋƵĞŶĐLJͿŝƐϲϬ͘Ϭ,nj͕ĞdžĐĞƉƚĚƵƌŝŶŐĂƚŝŵĞĐŽƌƌĞĐƚŝŽŶ͘
/D;/ŶƚĞƌĐŚĂŶŐĞDĞƚĞƌƌƌŽƌͿŝƐƚŚĞŵĞƚĞƌĞƌƌŽƌĐŽƌƌĞĐƚŝŽŶĨĂĐƚŽƌĂŶĚƌĞƉƌĞƐĞŶƚƐƚŚĞ
ĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶƚŚĞŝŶƚĞŐƌĂƚĞĚŚŽƵƌůLJĂǀĞƌĂŐĞŽĨƚŚĞŶĞƚŝŶƚĞƌĐŚĂŶŐĞĂĐƚƵĂů;E/ͿĂŶĚ
ƚŚĞĐƵŵƵůĂƚŝǀĞŚŽƵƌůLJŶĞƚŝŶƚĞƌĐŚĂŶŐĞĞŶĞƌŐLJŵĞĂƐƵƌĞŵĞŶƚ;ŝŶŵĞŐĂǁĂƚƚͲŚŽƵƌƐͿ͘
/d;ƵƚŽŵĂƚŝĐdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶͿŝƐƚŚĞĂĚĚŝƚŝŽŶŽĨĂĐŽŵƉŽŶĞŶƚƚŽƚŚĞĞƋƵĂƚŝŽŶ
ĨŽƌƚŚĞtĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶƚŚĂƚŵŽĚŝĨŝĞƐƚŚĞĐŽŶƚƌŽůƉŽŝŶƚĨŽƌƚŚĞƉƵƌƉŽƐĞŽĨ
ĐŽŶƚŝŶƵŽƵƐůLJƉĂLJŝŶŐďĂĐŬWƌŝŵĂƌLJ/ŶĂĚǀĞƌƚĞŶƚ/ŶƚĞƌĐŚĂŶŐĞƚŽĐŽƌƌĞĐƚĂĐĐƵŵƵůĂƚĞĚƚŝŵĞ
ĞƌƌŽƌ͘ƵƚŽŵĂƚŝĐdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶŝƐŽŶůLJĂƉƉůŝĐĂďůĞŝŶƚŚĞtĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͘
on/off peak

IATEC

= PII

accum

(1 − Y )* H

ǁŚĞŶŽƉĞƌĂƚŝŶŐŝŶƵƚŽŵĂƚŝĐdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶĐŽŶƚƌŽůŵŽĚĞ͘

/dƐŚĂůůďĞnjĞƌŽǁŚĞŶŽƉĞƌĂƚŝŶŐŝŶĂŶLJŽƚŚĞƌ'ŵŽĚĞ͘
•

zсͬ^͘

•

,сEƵŵďĞƌŽĨŚŽƵƌƐƵƐĞĚƚŽƉĂLJďĂĐŬWƌŝŵĂƌLJ/ŶĂĚǀĞƌƚĞŶƚ/ŶƚĞƌĐŚĂŶŐĞĞŶĞƌŐLJ͘dŚĞ
ǀĂůƵĞŽĨ,ŝƐƐĞƚƚŽϯ͘

>ͲϬϬϮͲϮʹŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ

ϯ

•

^с&ƌĞƋƵĞŶĐLJŝĂƐĨŽƌƚŚĞ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ;DtͬϬ͘ϭ,njͿ͘

•

WƌŝŵĂƌLJ/ŶĂĚǀĞƌƚĞŶƚ/ŶƚĞƌĐŚĂŶŐĞ;W//ŚŽƵƌůLJͿŝƐ;ϭͲzͿΎ;//ĂĐƚƵĂůͲΎȴdͬϲͿ

•

//ĂĐƚƵĂůŝƐƚŚĞŚŽƵƌůLJ/ŶĂĚǀĞƌƚĞŶƚ/ŶƚĞƌĐŚĂŶŐĞĨŽƌƚŚĞůĂƐƚŚŽƵƌ͘

•

ȴdŝƐƚŚĞŚŽƵƌůLJĐŚĂŶŐĞŝŶƐLJƐƚĞŵdŝŵĞƌƌŽƌĂƐĚŝƐƚƌŝďƵƚĞĚďLJƚŚĞ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ
dŝŵĞDŽŶŝƚŽƌ͘tŚĞƌĞ͗



ȴdсdĞŶĚŚŽƵƌʹdďĞŐŝŶŚŽƵƌʹdĂĚũʹ;ƚͿΎ;dŽĨĨƐĞƚͿ

•

dĂĚũŝƐƚŚĞZĞůŝĂďŝůŝƚLJŽŽƌĚŝŶĂƚŽƌĂĚũƵƐƚŵĞŶƚĨŽƌĚŝĨĨĞƌĞŶĐĞƐǁŝƚŚ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶdŝŵĞ
DŽŶŝƚŽƌĐŽŶƚƌŽůĐĞŶƚĞƌĐůŽĐŬƐ͘

•

ƚŝƐƚŚĞŶƵŵďĞƌŽĨŵŝŶƵƚĞƐŽĨDĂŶƵĂůdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶƚŚĂƚŽĐĐƵƌƌĞĚĚƵƌŝŶŐƚŚĞ
ŚŽƵƌ͘

•

dŽĨĨƐĞƚŝƐϬ͘ϬϬϬŽƌнϬ͘ϬϮϬŽƌͲϬ͘ϬϮϬ͘

•

W//ĂĐĐƵŵŝƐƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛ƐĂĐĐƵŵƵůĂƚĞĚW//ŚŽƵƌůLJŝŶDtŚ͘ŶKŶͲWĞĂŬĂŶĚKĨĨͲ
WĞĂŬĂĐĐƵŵƵůĂƚŝŽŶĂĐĐŽƵŶƚŝŶŐŝƐƌĞƋƵŝƌĞĚ͘
tŚĞƌĞ͗

PII

on/off peak
accum

сůĂƐƚƉĞƌŝŽĚ͛Ɛ

on/off peak

PII

accum

нW//ŚŽƵƌůLJ


ůůEZ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶƐǁŝƚŚŵƵůƚŝƉůĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐŽƉĞƌĂƚĞƵƐŝŶŐƚŚĞƉƌŝŶĐŝƉůĞƐŽĨ
dŝĞͲůŝŶĞŝĂƐ;d>ͿŽŶƚƌŽůĂŶĚƌĞƋƵŝƌĞƚŚĞƵƐĞŽĨĂŶĞƋƵĂƚŝŽŶƐŝŵŝůĂƌƚŽƚŚĞZĞƉŽƌƚŝŶŐ
ĚĞĨŝŶĞĚĂďŽǀĞ͘ŶLJŵŽĚŝĨŝĐĂƚŝŽŶ;ƐͿƚŽƚŚŝƐƐƉĞĐŝĨŝĞĚZĞƉŽƌƚŝŶŐĞƋƵĂƚŝŽŶƚŚĂƚŝƐ;ĂƌĞͿ
ŝŵƉůĞŵĞŶƚĞĚĨŽƌĂůůƐŽŶĂŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶĂŶĚŝƐ;ĂƌĞͿĐŽŶƐŝƐƚĞŶƚǁŝƚŚƚŚĞĨŽůůŽǁŝŶŐĨŽƵƌ
ƉƌŝŶĐŝƉůĞƐǁŝůůƉƌŽǀŝĚĞĂǀĂůŝĚĂůƚĞƌŶĂƚŝǀĞZĞƉŽƌƚŝŶŐĞƋƵĂƚŝŽŶĐŽŶƐŝƐƚĞŶƚǁŝƚŚƚŚĞ
ŵĞĂƐƵƌĞƐŝŶĐůƵĚĞĚŝŶƚŚŝƐƐƚĂŶĚĂƌĚ͘
ϭ͘ ůůƉŽƌƚŝŽŶƐŽĨƚŚĞ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶĂƌĞŝŶĐůƵĚĞĚŝŶŽŶĞĂƌĞĂŽƌĂŶŽƚŚĞƌƐŽƚŚĂƚƚŚĞ
ƐƵŵŽĨĂůůĂƌĞĂŐĞŶĞƌĂƚŝŽŶ͕ůŽĂĚƐĂŶĚůŽƐƐĞƐŝƐƚŚĞƐĂŵĞĂƐƚŽƚĂůƐLJƐƚĞŵŐĞŶĞƌĂƚŝŽŶ͕
ůŽĂĚĂŶĚůŽƐƐĞƐ͘
Ϯ͘ dŚĞĂůŐĞďƌĂŝĐƐƵŵŽĨĂůůĂƌĞĂEĞƚ/ŶƚĞƌĐŚĂŶŐĞ^ĐŚĞĚƵůĞƐĂŶĚĂůůEĞƚ/ŶƚĞƌĐŚĂŶŐĞ
ĂĐƚƵĂůǀĂůƵĞƐŝƐĞƋƵĂůƚŽnjĞƌŽĂƚĂůůƚŝŵĞƐ͘
ϯ͘ dŚĞƵƐĞŽĨĂĐŽŵŵŽŶ^ĐŚĞĚƵůĞĚ&ƌĞƋƵĞŶĐLJ&^ĨŽƌĂůůĂƌĞĂƐĂƚĂůůƚŝŵĞƐ͘
ϰ͘ dŚĞĂďƐĞŶĐĞŽĨŵĞƚĞƌŝŶŐŽƌĐŽŵƉƵƚĂƚŝŽŶĂůĞƌƌŽƌƐ͘;dŚĞŝŶĐůƵƐŝŽŶĂŶĚƵƐĞŽĨƚŚĞ/D
ƚĞƌŵƚŽĂĐĐŽƵŶƚĨŽƌŬŶŽǁŶŵĞƚĞƌŝŶŐŽƌĐŽŵƉƵƚĂƚŝŽŶĂůĞƌƌŽƌƐ͘Ϳ
ƉƉůŝĐĂďůĞŶƚŝƚŝĞƐ
ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ

>ͲϬϬϮͲϮʹŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ

ϰ

ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ

ƉƉůŝĐĂďůĞ&ĂĐŝůŝƚŝĞƐ
Eͬ

ŽŶĨŽƌŵŝŶŐŚĂŶŐĞƐƚŽKƚŚĞƌ^ƚĂŶĚĂƌĚƐ
EŽŶĞ

ĨĨĞĐƚŝǀĞĂƚĞƐ
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&ŝƌƐƚĚĂLJŽĨƚŚĞĨŝƌƐƚĐĂůĞŶĚĂƌƋƵĂƌƚĞƌƚŚĂƚŝƐƐŝdžŵŽŶƚŚƐďĞLJŽŶĚƚŚĞĚĂƚĞƚŚĂƚƚŚŝƐƐƚĂŶĚĂƌĚŝƐ
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ŝŝ͘ >ŽƐƐŽĨŐĞŶĞƌĂƚŽƌ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ&ĂĐŝůŝƚLJƌĞƐƵůƚŝŶŐŝŶŝƐŽůĂƚŝŽŶŽĨƚŚĞ
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ƵƚŚŽƌŝƚLJͿ͘
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ŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͗ƉĞƌŝŽĚďĞŐŝŶŶŝŶŐĂƚƚŚĞƚŝŵĞƚŚĂƚƚŚĞƌĞƐŽƵƌĐĞŽƵƚƉƵƚ
ďĞŐŝŶƐƚŽĚĞĐůŝŶĞǁŝƚŚŝŶƚŚĞĨŝƌƐƚŽŶĞͲŵŝŶƵƚĞŝŶƚĞƌǀĂůƚŚĂƚĚĞĨŝŶĞƐĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͕
ĂŶĚĞdžƚĞŶĚƐĨŽƌĨŝĨƚĞĞŶŵŝŶƵƚĞƐƚŚĞƌĞĂĨƚĞƌ͘
ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚ͗ƉĞƌŝŽĚŶŽƚĞdžĐĞĞĚŝŶŐϵϬŵŝŶƵƚĞƐĨŽůůŽǁŝŶŐƚŚĞĞŶĚŽĨ
ƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͘

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^ŚĂƌŝŶŐ'ƌŽƵƉZĞƉŽƌƚŝŶŐǁŚĞŶĂƉƉůŝĐĂďůĞ͕ŝŶƚŚĞϭϲƐĞĐŽŶĚŝŶƚĞƌǀĂůŝŵŵĞĚŝĂƚĞůLJƉƌŝŽƌƚŽƚŚĞ
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ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉZĞƉŽƌƚŝŶŐ͗ƚĂŶLJŐŝǀĞŶƚŝŵĞŽĨŵĞĂƐƵƌĞŵĞŶƚĨŽƌƚŚĞĂƉƉůŝĐĂďůĞ
ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ͕ƚŚĞĂůŐĞďƌĂŝĐƐƵŵŽĨƚŚĞƐ;ŽƌĞƋƵŝǀĂůĞŶƚĂƐĐĂůĐƵůĂƚĞĚĂƚƐƵĐŚƚŝŵĞŽĨ
ŵĞĂƐƵƌĞŵĞŶƚͿŽĨĂůůŽĨƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐƉĂƌƚŝĐŝƉĂƚŝŶŐŝŶƚŚĂƚŵĂŬĞƵƉƚŚĞZĞƐĞƌǀĞ^ŚĂƌŝŶŐ
'ƌŽƵƉĂƚƚŚĞƚŝŵĞŽĨŵĞĂƐƵƌĞŵĞŶƚ͘

ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ͗dŚĞƉƌŽǀŝƐŝŽŶŽĨĐĂƉĂĐŝƚLJƚŚĂƚŵĂLJďĞĚĞƉůŽLJĞĚďLJƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJƚŽ
ƌĞƐƉŽŶĚƚŽĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚŽƚŚĞƌEZĐŽŶƚŝŶŐĞŶĐLJƌĞƋƵŝƌĞŵĞŶƚƐ;ƐƵĐŚĂƐ
ŶĞƌŐLJŵĞƌŐĞŶĐLJůĞƌƚƐ>ĞǀĞůϮŽƌ>ĞǀĞůϯͿ͘dŚĞĐĂƉĂĐŝƚLJŵĂLJďĞƉƌŽǀŝĚĞĚďLJƌĞƐŽƵƌĐĞƐƐƵĐŚĂƐ
ĞŵĂŶĚ^ŝĚĞDĂŶĂŐĞŵĞŶƚ;^DͿ͕/ŶƚĞƌƌƵƉƚŝďůĞ>ŽĂĚĂŶĚƵŶůŽĂĚĞĚŐĞŶĞƌĂƚŝŽŶ͘͘
ZĞƉŽƌƚŝŶŐ͗dŚĞƐĐĂŶƌĂƚĞǀĂůƵĞƐŽĨĂĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛ƐƌĞĂŽŶƚƌŽůƌƌŽƌ;ͿŵĞĂƐƵƌĞĚ
ŝŶDt͕ǁŚŝĐŚŝŶĐůƵĚĞƐƚŚĞĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛ƐEĞƚĐƚƵĂů/ŶƚĞƌĐŚĂŶŐĞ

>ͲϬϬϮͲϮʹŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ

Ϯ

ĂŶĚŝƚƐEĞƚ^ĐŚĞĚƵůĞĚ/ŶƚĞƌĐŚĂŶŐĞ͕ƉůƵƐŝƚƐ&ƌĞƋƵĞŶĐLJŝĂƐŽďůŝŐĂƚŝŽŶ͕ƉůƵƐĂŶLJŬŶŽǁŶŵĞƚĞƌĞƌƌŽƌ͘
/ŶƚŚĞtĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͕ZĞƉŽƌƚŝŶŐŝŶĐůƵĚĞƐƵƚŽŵĂƚŝĐdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶ;dͿ͘
ZĞƉŽƌƚŝŶŐŝƐĐĂůĐƵůĂƚĞĚĂƐĨŽůůŽǁƐ͗

ZĞƉŽƌƚŝŶŐс;E/оE/^ͿоϭϬ;&о&^Ϳо/D
ZĞƉŽƌƚŝŶŐŝƐĐĂůĐƵůĂƚĞĚŝŶƚŚĞtĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶĂƐĨŽůůŽǁƐ͗

ZĞƉŽƌƚŝŶŐс;E/оE/^ͿоϭϬ;&о&^Ϳо/Dн/d
tŚĞƌĞ͗
E/;ĐƚƵĂůEĞƚ/ŶƚĞƌĐŚĂŶŐĞͿŝƐƚŚĞĂůŐĞďƌĂŝĐƐƵŵŽĨĂĐƚƵĂůŵĞŐĂǁĂƚƚƚƌĂŶƐĨĞƌƐĂĐƌŽƐƐĂůůdŝĞ
>ŝŶĞƐĂŶĚŝŶĐůƵĚĞƐWƐĞƵĚŽͲdŝĞƐ͘ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐĚŝƌĞĐƚůLJĐŽŶŶĞĐƚĞĚǀŝĂĂƐLJŶĐŚƌŽŶŽƵƐ
ƚŝĞƐƚŽĂŶŽƚŚĞƌ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶŵĂLJŝŶĐůƵĚĞŽƌĞdžĐůƵĚĞŵĞŐĂǁĂƚƚƚƌĂŶƐĨĞƌƐŽŶƚŚŽƐĞdŝĞ
>ŝŶĞƐŝŶƚŚĞŝƌĂĐƚƵĂůŝŶƚĞƌĐŚĂŶŐĞ͕ƉƌŽǀŝĚĞĚƚŚĞLJĂƌĞŝŵƉůĞŵĞŶƚĞĚŝŶƚŚĞƐĂŵĞŵĂŶŶĞƌĨŽƌ
EĞƚ/ŶƚĞƌĐŚĂŶŐĞ^ĐŚĞĚƵůĞ͘
E/^;^ĐŚĞĚƵůĞĚEĞƚ/ŶƚĞƌĐŚĂŶŐĞͿŝƐƚŚĞĂůŐĞďƌĂŝĐƐƵŵŽĨĂůůƐĐŚĞĚƵůĞĚŵĞŐĂǁĂƚƚƚƌĂŶƐĨĞƌƐ͕
ŝŶĐůƵĚŝŶŐLJŶĂŵŝĐ^ĐŚĞĚƵůĞƐ͕ǁŝƚŚĂĚũĂĐĞŶƚĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐ͕ĂŶĚƚĂŬŝŶŐŝŶƚŽĂĐĐŽƵŶƚ
ƚŚĞĞĨĨĞĐƚƐŽĨƐĐŚĞĚƵůĞƌĂŵƉƐ͘ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐĚŝƌĞĐƚůLJĐŽŶŶĞĐƚĞĚǀŝĂĂƐLJŶĐŚƌŽŶŽƵƐ
ƚŝĞƐƚŽĂŶŽƚŚĞƌ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶŵĂLJŝŶĐůƵĚĞŽƌĞdžĐůƵĚĞŵĞŐĂǁĂƚƚƚƌĂŶƐĨĞƌƐŽŶƚŚŽƐĞdŝĞ
>ŝŶĞƐŝŶƚŚĞŝƌƐĐŚĞĚƵůĞĚ/ŶƚĞƌĐŚĂŶŐĞ͕ƉƌŽǀŝĚĞĚƚŚĞLJĂƌĞŝŵƉůĞŵĞŶƚĞĚŝŶƚŚĞƐĂŵĞŵĂŶŶĞƌ
ĨŽƌEĞƚ/ŶƚĞƌĐŚĂŶŐĞĐƚƵĂů͘
;&ƌĞƋƵĞŶĐLJŝĂƐ^ĞƚƚŝŶŐͿŝƐƚŚĞ&ƌĞƋƵĞŶĐLJŝĂƐ^ĞƚƚŝŶŐ;ŝŶŶĞŐĂƚŝǀĞDtͬϬ͘ϭ,njͿĨŽƌƚŚĞ
ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͘
ϭϬŝƐƚŚĞĐŽŶƐƚĂŶƚĨĂĐƚŽƌƚŚĂƚĐŽŶǀĞƌƚƐƚŚĞ&ƌĞƋƵĞŶĐLJŝĂƐ^ĞƚƚŝŶŐƵŶŝƚƐƚŽDtͬ,nj͘
&;ĐƚƵĂů&ƌĞƋƵĞŶĐLJͿŝƐƚŚĞŵĞĂƐƵƌĞĚĨƌĞƋƵĞŶĐLJŝŶ,nj͘
&^;^ĐŚĞĚƵůĞĚ&ƌĞƋƵĞŶĐLJͿŝƐϲϬ͘Ϭ,nj͕ĞdžĐĞƉƚĚƵƌŝŶŐĂƚŝŵĞĐŽƌƌĞĐƚŝŽŶ͘
/D;/ŶƚĞƌĐŚĂŶŐĞDĞƚĞƌƌƌŽƌͿŝƐƚŚĞŵĞƚĞƌĞƌƌŽƌĐŽƌƌĞĐƚŝŽŶĨĂĐƚŽƌĂŶĚƌĞƉƌĞƐĞŶƚƐƚŚĞ
ĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶƚŚĞŝŶƚĞŐƌĂƚĞĚŚŽƵƌůLJĂǀĞƌĂŐĞŽĨƚŚĞŶĞƚŝŶƚĞƌĐŚĂŶŐĞĂĐƚƵĂů;E/ͿĂŶĚ
ƚŚĞĐƵŵƵůĂƚŝǀĞŚŽƵƌůLJŶĞƚŝŶƚĞƌĐŚĂŶŐĞĞŶĞƌŐLJŵĞĂƐƵƌĞŵĞŶƚ;ŝŶŵĞŐĂǁĂƚƚͲŚŽƵƌƐͿ͘
/d;ƵƚŽŵĂƚŝĐdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶͿŝƐƚŚĞĂĚĚŝƚŝŽŶŽĨĂĐŽŵƉŽŶĞŶƚƚŽƚŚĞĞƋƵĂƚŝŽŶ
ĨŽƌƚŚĞtĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶƚŚĂƚŵŽĚŝĨŝĞƐƚŚĞĐŽŶƚƌŽůƉŽŝŶƚĨŽƌƚŚĞƉƵƌƉŽƐĞŽĨ
ĐŽŶƚŝŶƵŽƵƐůLJƉĂLJŝŶŐďĂĐŬWƌŝŵĂƌLJ/ŶĂĚǀĞƌƚĞŶƚ/ŶƚĞƌĐŚĂŶŐĞƚŽĐŽƌƌĞĐƚĂĐĐƵŵƵůĂƚĞĚƚŝŵĞ
ĞƌƌŽƌ͘ƵƚŽŵĂƚŝĐdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶŝƐŽŶůLJĂƉƉůŝĐĂďůĞŝŶƚŚĞtĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͘
on/off peak

IATEC

= PII

accum

(1 − Y )* H

ǁŚĞŶŽƉĞƌĂƚŝŶŐŝŶƵƚŽŵĂƚŝĐdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶĐŽŶƚƌŽůŵŽĚĞ͘

/dƐŚĂůůďĞnjĞƌŽǁŚĞŶŽƉĞƌĂƚŝŶŐŝŶĂŶLJŽƚŚĞƌ'ŵŽĚĞ͘
•

zсͬ^͘

•

,сEƵŵďĞƌŽĨŚŽƵƌƐƵƐĞĚƚŽƉĂLJďĂĐŬWƌŝŵĂƌLJ/ŶĂĚǀĞƌƚĞŶƚ/ŶƚĞƌĐŚĂŶŐĞĞŶĞƌŐLJ͘dŚĞ
ǀĂůƵĞŽĨ,ŝƐƐĞƚƚŽϯ͘

>ͲϬϬϮͲϮʹŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ

ϯ

•

^с&ƌĞƋƵĞŶĐLJŝĂƐĨŽƌƚŚĞ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ;DtͬϬ͘ϭ,njͿ͘

•

WƌŝŵĂƌLJ/ŶĂĚǀĞƌƚĞŶƚ/ŶƚĞƌĐŚĂŶŐĞ;W//ŚŽƵƌůLJͿŝƐ;ϭͲzͿΎ;//ĂĐƚƵĂůͲΎȴdͬϲͿ

•

//ĂĐƚƵĂůŝƐƚŚĞŚŽƵƌůLJ/ŶĂĚǀĞƌƚĞŶƚ/ŶƚĞƌĐŚĂŶŐĞĨŽƌƚŚĞůĂƐƚŚŽƵƌ͘

•

ȴdŝƐƚŚĞŚŽƵƌůLJĐŚĂŶŐĞŝŶƐLJƐƚĞŵdŝŵĞƌƌŽƌĂƐĚŝƐƚƌŝďƵƚĞĚďLJƚŚĞ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ
dŝŵĞDŽŶŝƚŽƌ͘tŚĞƌĞ͗



ȴdсdĞŶĚŚŽƵƌʹdďĞŐŝŶŚŽƵƌʹdĂĚũʹ;ƚͿΎ;dŽĨĨƐĞƚͿ

•

dĂĚũŝƐƚŚĞZĞůŝĂďŝůŝƚLJŽŽƌĚŝŶĂƚŽƌĂĚũƵƐƚŵĞŶƚĨŽƌĚŝĨĨĞƌĞŶĐĞƐǁŝƚŚ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶdŝŵĞ
DŽŶŝƚŽƌĐŽŶƚƌŽůĐĞŶƚĞƌĐůŽĐŬƐ͘

•

ƚŝƐƚŚĞŶƵŵďĞƌŽĨŵŝŶƵƚĞƐŽĨDĂŶƵĂůdŝŵĞƌƌŽƌŽƌƌĞĐƚŝŽŶƚŚĂƚŽĐĐƵƌƌĞĚĚƵƌŝŶŐƚŚĞ
ŚŽƵƌ͘

•

dŽĨĨƐĞƚŝƐϬ͘ϬϬϬŽƌнϬ͘ϬϮϬŽƌͲϬ͘ϬϮϬ͘

•

W//ĂĐĐƵŵŝƐƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛ƐĂĐĐƵŵƵůĂƚĞĚW//ŚŽƵƌůLJŝŶDtŚ͘ŶKŶͲWĞĂŬĂŶĚKĨĨͲ
WĞĂŬĂĐĐƵŵƵůĂƚŝŽŶĂĐĐŽƵŶƚŝŶŐŝƐƌĞƋƵŝƌĞĚ͘
tŚĞƌĞ͗

PII

on/off peak
accum

сůĂƐƚƉĞƌŝŽĚ͛Ɛ

on/off peak

PII

accum

нW//ŚŽƵƌůLJ


ůůEZ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶƐǁŝƚŚŵƵůƚŝƉůĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐŽƉĞƌĂƚĞƵƐŝŶŐƚŚĞƉƌŝŶĐŝƉůĞƐŽĨ
dŝĞͲůŝŶĞŝĂƐ;d>ͿŽŶƚƌŽůĂŶĚƌĞƋƵŝƌĞƚŚĞƵƐĞŽĨĂŶĞƋƵĂƚŝŽŶƐŝŵŝůĂƌƚŽƚŚĞZĞƉŽƌƚŝŶŐ
ĚĞĨŝŶĞĚĂďŽǀĞ͘ŶLJŵŽĚŝĨŝĐĂƚŝŽŶ;ƐͿƚŽƚŚŝƐƐƉĞĐŝĨŝĞĚZĞƉŽƌƚŝŶŐĞƋƵĂƚŝŽŶƚŚĂƚŝƐ;ĂƌĞͿ
ŝŵƉůĞŵĞŶƚĞĚĨŽƌĂůůƐŽŶĂŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶĂŶĚŝƐ;ĂƌĞͿĐŽŶƐŝƐƚĞŶƚǁŝƚŚƚŚĞĨŽůůŽǁŝŶŐĨŽƵƌ
ƉƌŝŶĐŝƉůĞƐǁŝůůƉƌŽǀŝĚĞĂǀĂůŝĚĂůƚĞƌŶĂƚŝǀĞZĞƉŽƌƚŝŶŐĞƋƵĂƚŝŽŶĐŽŶƐŝƐƚĞŶƚǁŝƚŚƚŚĞ
ŵĞĂƐƵƌĞƐŝŶĐůƵĚĞĚŝŶƚŚŝƐƐƚĂŶĚĂƌĚ͘
ϭ͘ ůůƉŽƌƚŝŽŶƐŽĨƚŚĞ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶĂƌĞŝŶĐůƵĚĞĚŝŶŽŶĞĂƌĞĂŽƌĂŶŽƚŚĞƌƐŽƚŚĂƚƚŚĞ
ƐƵŵŽĨĂůůĂƌĞĂŐĞŶĞƌĂƚŝŽŶ͕ůŽĂĚƐĂŶĚůŽƐƐĞƐŝƐƚŚĞƐĂŵĞĂƐƚŽƚĂůƐLJƐƚĞŵŐĞŶĞƌĂƚŝŽŶ͕
ůŽĂĚĂŶĚůŽƐƐĞƐ͘
Ϯ͘ dŚĞĂůŐĞďƌĂŝĐƐƵŵŽĨĂůůĂƌĞĂEĞƚ/ŶƚĞƌĐŚĂŶŐĞ^ĐŚĞĚƵůĞƐĂŶĚĂůůEĞƚ/ŶƚĞƌĐŚĂŶŐĞ
ĂĐƚƵĂůǀĂůƵĞƐŝƐĞƋƵĂůƚŽnjĞƌŽĂƚĂůůƚŝŵĞƐ͘
ϯ͘ dŚĞƵƐĞŽĨĂĐŽŵŵŽŶ^ĐŚĞĚƵůĞĚ&ƌĞƋƵĞŶĐLJ&^ĨŽƌĂůůĂƌĞĂƐĂƚĂůůƚŝŵĞƐ͘
ϰ͘ dŚĞĂďƐĞŶĐĞŽĨŵĞƚĞƌŝŶŐŽƌĐŽŵƉƵƚĂƚŝŽŶĂůĞƌƌŽƌƐ͘;dŚĞŝŶĐůƵƐŝŽŶĂŶĚƵƐĞŽĨƚŚĞ/D
ƚĞƌŵƚŽĂĐĐŽƵŶƚĨŽƌŬŶŽǁŶŵĞƚĞƌŝŶŐŽƌĐŽŵƉƵƚĂƚŝŽŶĂůĞƌƌŽƌƐ͘Ϳ
ƉƉůŝĐĂďůĞŶƚŝƚŝĞƐ
ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ

>ͲϬϬϮͲϮʹŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ

ϰ

ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ

ƉƉůŝĐĂďůĞ&ĂĐŝůŝƚŝĞƐ
Eͬ

ŽŶĨŽƌŵŝŶŐŚĂŶŐĞƐƚŽKƚŚĞƌ^ƚĂŶĚĂƌĚƐ
EŽŶĞ

ĨĨĞĐƚŝǀĞĂƚĞƐ
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&ŝƌƐƚĚĂLJŽĨƚŚĞĨŝƌƐƚĐĂůĞŶĚĂƌƋƵĂƌƚĞƌƚŚĂƚŝƐƐŝdžŵŽŶƚŚƐďĞLJŽŶĚƚŚĞĚĂƚĞƚŚĂƚƚŚŝƐƐƚĂŶĚĂƌĚŝƐ
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ZĞƚŝƌĞŵĞŶƚƐ
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>ͲϬϬϮͲϮʹŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
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Unofficial Comment Form

Project 2010-14.1 Balancing Authority Reliability-based Control
BAL-002-2 Contingency Reserve for Recovery from a
Contingency Event
Please do not use this form to submit comments on the proposed revisions to BAL-002-2 Contingency
Reserve for Recovery from a Contingency Event. Comments must be submitted using the electronic
comment form by 8 p.m. ET on Monday, September 16, 2013.
If you have questions please contact Darrel Richardson (via email) or by telephone at (609) 613-1848.
Background Information:

Since loss of generation occurrences so often impacts all Balancing Authorities throughout an
Interconnection, BAL-002 was created to specify recovery actions and time frames. The original
Standards Authorization Request (SAR) approved by the Industry presumes there is presently sufficient
contingency reserve in all the North American Interconnections. The underlying goal of the SAR was to
update the Standard to make the measurement process more objective and to provide information to
the Balancing Authority or Reserve Sharing Group such that the parties would better understand the
use of contingency reserve to balance resources and demand following a Reportable Contingency Event.
The primary objective of BAL-002-2 is to measure the success of recovering from contingency events.
Based on comments received from industry stakeholders the drafting team made the following
modifications to the draft standard.
x

Modified the definition for a Balancing Contingency Event to provide additional clarity.

x

Modified the definition for a Reportable Balancing Contingency Event to use Interconnection
specific thresholds instead of a continent wide threshold.

x

Modified the definition for Pre-Reporting Contingency Event ACE Value to provide additional clarity.

x

Modified the definition for Reserve Sharing Group Reporting ACE to provide additional clarity.

x

Modified the definition for Contingency Reserve to provide additional clarity.

x

Modified Requirements R1 and R2 to provide additional clarity.

x

Modified the VSL for Requirement R1 to provide additional clarity.

x

Modified the Background Document to provide additional clarity.

Questions

Enter comments in simple text format. Bullets, numbers, and special formatting will not be retained.
1. Please provide any issues you have on this draft of the BAL-002-2 standard and a proposed solution.
Comments:

Unofficial Comment Form
BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event

2




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Table of Contents ............................................................................................................................ 2
/ŶƚƌŽĚƵĐƚŝŽŶ .................................................................................................................................... 3
Requirement 1 ................................................................................................................................. 5
Requirement 2 ............................................................................................................................... 10

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ĞŶƚŝƚLJďĂůĂŶĐĞƐƌĞƐŽƵƌĐĞƐĂŶĚĚĞŵĂŶĚĂŶĚƌĞƚƵƌŶƐŝƚƐƌĞĂŽŶƚƌŽůƌƌŽƌƚŽĚĞĨŝŶĞĚǀĂůƵĞƐ
;ƐƵďũĞĐƚƚŽĂƉƉůŝĐĂďůĞůŝŵŝƚƐͿĨŽůůŽǁŝŶŐĂZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͘


ĂĐŬŐƌŽƵŶĚ

dŚŝƐƐĞĐƚŝŽŶĚŝƐĐƵƐƐĞƐƚŚĞŶĞǁĚĞĨŝŶŝƚŝŽŶƐĂƐƐŽĐŝĂƚĞĚǁŝƚŚ>ͲϬϬϮͲϮ͘
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
dŚĞƉƵƌƉŽƐĞŽĨ>ͲϬϬϮͲϮŝƐƚŽĞŶƐƵƌĞƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJŽƌZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ
ďĂůĂŶĐĞƌĞƐŽƵƌĐĞƐĂŶĚĚĞŵĂŶĚďLJƌĞƚƵƌŶŝŶŐŝƚƐƌĞĂŽŶƚƌŽůƌƌŽƌƚŽĚĞĨŝŶĞĚǀĂůƵĞƐĨŽůůŽǁŝŶŐĂ
ZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͘
dŚĞĚƌĂĨƚŝŶŐƚĞĂŵŝŶĐůƵĚĞĚĂƐƉĞĐŝĨŝĐĚĞĨŝŶŝƚŝŽŶĨŽƌĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƚŽĞůŝŵŝŶĂƚĞ
ĂŶLJĐŽŶĨƵƐŝŽŶĂŶĚĂŵďŝŐƵŝƚLJ͘dŚĞƉƌŝŽƌǀĞƌƐŝŽŶŽĨ>ͲϬϬϮǁĂƐďƌŽĂĚĂŶĚĐŽƵůĚďĞŝŶƚĞƌƉƌĞƚĞĚ
ŝŶǀĂƌŝŽƵƐŵĂŶŶĞƌƐůĞĂǀŝŶŐƚŚĞĂďŝůŝƚLJƚŽŵĞĂƐƵƌĞĐŽŵƉůŝĂŶĐĞƵƉƚŽƚŚĞĞLJĞŽĨƚŚĞďĞŚŽůĚĞƌ͘LJ
ŝŶĐůƵĚŝŶŐƚŚĞƐƉĞĐŝĨŝĐĚĞĨŝŶŝƚŝŽŶ͕ŝƚĂůůŽǁƐƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJƚŽĨƵůůLJƵŶĚĞƌƐƚĂŶĚŚŽǁƚŽ
ƉĞƌĨŽƌŵĂŶĚŵĞĞƚĐŽŵƉůŝĂŶĐĞ͘ůƐŽ͕&ZKƌĚĞƌϲϵϯ;ĂƚWϯϱϱͿĚŝƌĞĐƚĞĚĞŶƚŝƚŝĞƐƚŽŝŶĐůƵĚĞĂ
ZĞƋƵŝƌĞŵĞŶƚƚŚĂƚŵĞĂƐƵƌĞƐƌĞƐƉŽŶƐĞĨŽƌĂŶLJĞǀĞŶƚŽƌĐŽŶƚŝŶŐĞŶĐLJƚŚĂƚĐĂƵƐĞƐĂĨƌĞƋƵĞŶĐLJ
ĚĞǀŝĂƚŝŽŶ͘LJĚĞǀĞůŽƉŝŶŐĂƐƉĞĐŝĨŝĐĚĞĨŝŶŝƚŝŽŶƚŚĂƚĚĞƉŝĐƚƐƚŚĞĞǀĞŶƚƐĐĂƵƐŝŶŐĂŶƵŶĞdžƉĞĐƚĞĚ
ĐŚĂŶŐĞƚŽƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛Ɛ͕ƚŚĞŶĞĐĞƐƐĂƌLJƌĞƋƵŝƌĞŵĞŶƚƐĂƐƐƵƌĞƐ&Z͛Ɛ
ƌĞƋƵŝƌĞŵĞŶƚŝƐŵĞƚ͘
DŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ
dŚĞDŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;D^^ͿƚĞƌŵŚĂƐďĞĞŶǁŝĚĞůLJƵƐĞĚǁŝƚŚŝŶƚŚĞŝŶĚƵƐƚƌLJ͖
ŚŽǁĞǀĞƌ͕ŝƚŚĂƐŶĞǀĞƌďĞĞŶĚĞĨŝŶĞĚ͘/ŶŽƌĚĞƌƚŽĞůŝŵŝŶĂƚĞĂǁŝĚĞƌĂŶŐĞŽĨĚĞĨŝŶŝƚŝŽŶƐ͕ƚŚĞ
ĚƌĂĨƚŝŶŐƚĞĂŵŚĂƐŝŶĐůƵĚĞĚĂƐƉĞĐŝĨŝĐĚĞĨŝŶŝƚŝŽŶĚĞƐŝŐŶĞĚƚŽĨƵůĨŝůůƚŚĞŶĞĞĚƐŽĨƚŚĞƐƚĂŶĚĂƌĚ͘/Ŷ
ĂĚĚŝƚŝŽŶ͕ŝŶŽƌĚĞƌƚŽŵĞĞƚ&ZKƌĚĞƌEŽ͘ϲϵϯ;ĂƚWϯϱϲͿ͕ƚŽĚĞǀĞůŽƉĂĐŽŶƚŝŶĞŶƚͲǁŝĚĞ
ĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƉŽůŝĐLJ͕ŝƚǁĂƐŶĞĐĞƐƐĂƌLJƚŽĞƐƚĂďůŝƐŚĂĚĞĨŝŶŝƚŝŽŶĨŽƌD^^͘
ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ
DŽƐƚƐLJƐƚĞŵŽƉĞƌĂƚŽƌƐŐĞŶĞƌĂůůLJŚĂǀĞĂŐŽŽĚƵŶĚĞƌƐƚĂŶĚŝŶŐŽĨƚŚĞŶĞĞĚƚŽďĂůĂŶĐĞƌĞƐŽƵƌĐĞƐ
ĂŶĚĚĞŵĂŶĚĂŶĚƌĞƚƵƌŶƚŚĞŝƌƌĞĂŽŶƚƌŽůƌƌŽƌƚŽĚĞĨŝŶĞĚǀĂůƵĞƐĨŽůůŽǁŝŶŐĂZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͘,ŽǁĞǀĞƌ͕ƚŚĞĞdžŝƐƚŝŶŐĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞĚĞĨŝŶŝƚŝŽŶƐƉƌŝŵĂƌŝůLJ
ĨŽĐƵƐĞĚŽŶŐĞŶĞƌĂƚŝŽŶĂŶĚŶŽƚĚĞŵĂŶĚƐŝĚĞŵĂŶĂŐĞŵĞŶƚ͘/ŶŽƌĚĞƌƚŽŵĞĞƚ&ZKƌĚĞƌEŽ͘
ϲϵϯ;ĂƚWϯϱϲͿƚŽŝŶĐůƵĚĞĂZĞƋƵŝƌĞŵĞŶƚƚŚĂƚĞdžƉůŝĐŝƚůLJĂůůŽǁƐĚĞŵĂŶĚͲƐŝĚĞŵĂŶĂŐĞŵĞŶƚ;^DͿ
ƚŽďĞƵƐĞĚĂƐĂƌĞƐŽƵƌĐĞĨŽƌĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞ͕ƚŚĞĚƌĂĨƚŝŶŐƚĞĂŵĞůĞĐƚĞĚƚŽĞdžƉĂŶĚƚŚĞ
ĚĞĨŝŶŝƚŝŽŶŽĨŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞƚŽĞdžƉůŝĐŝƚůLJŝŶĐůƵĚĞĐĂƉĂĐŝƚLJĂƐƐŽĐŝĂƚĞĚǁŝƚŚĚĞŵĂŶĚƐŝĚĞ
ŵĂŶĂŐĞŵĞŶƚ͘
ĚĚŝƚŝŽŶĂůůLJ͕ĐŽŶĨůŝĐƚĞdžŝƐƚĞĚďĞƚǁĞĞŶ>ͲϬϬϮĂŶĚKWͲϬϬϮĂƐƚŽǁŚĞŶĂŶĞŶƚŝƚLJĐŽƵůĚĚĞƉůŽLJ
ŝƚƐĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞ͘dŽĞůŝŵŝŶĂƚĞƚŚĞƉŽƐƐŝďůĞĐŽŶĨůŝĐƚĂŶĚƚŽĂƐƐƵƌĞ>ͲϬϬϮĂŶĚKWͲϬϬϮ
ǁŽƌŬƚŽŐĞƚŚĞƌĂŶĚĐŽŵƉůŝŵĞŶƚĞĚĞĂĐŚŽƚŚĞƌ͕ƚŚĞĚƌĂĨƚŝŶŐƚĞĂŵĐůĂƌŝĨŝĞĚƚŚĞĞdžŝƐƚŝŶŐĚĞĨŝŶŝƚŝŽŶ
>ͲϬϬϮͲϮͲĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
:ƵůLJ͕ϮϬϭϯ

ϰ

ŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ&ƌŽŵĂĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ^ƚĂŶĚĂƌĚĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
ŽĨŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ͘dŚĞĐŽŶĨůŝĐƚĂƌŝƐĞƐƐŝŶĐĞƚŚĞĂĐƚŝŽŶƐƌĞƋƵŝƌĞĚďLJŶĞƌŐLJĞĨŝĐŝĞŶƚ
ŶƚŝƚŝĞƐďĞĨŽƌĞĚĞĐůĂƌŝŶŐĞŝƚŚĞƌĂŶŶĞƌŐLJŵĞƌŐĞŶĐLJůĞƌƚϮŽƌĂŶŶĞƌŐLJŵĞƌŐĞŶĐLJůĞƌƚϯ
ƌĞƋƵŝƌĞƐĚĞƉůŽLJŵĞŶƚŽĨĂůůKƉĞƌĂƚŝŶŐƌĞƐĞƌǀĞǁŚŝĐŚŝŶĐůƵĚĞƐŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ͘ŶŶĞƌŐLJ
ĞĨŝĐŝĞŶƚŶƚŝƚLJŵĂLJŶĞĞĚƚŽĚĞĐůĂƌĞĞŝƚŚĞƌĂŶŶĞƌŐLJŵĞƌŐĞŶĐLJůĞƌƚϮŽƌĂŶŶĞƌŐLJ
ŵĞƌŐĞŶĐLJůĞƌƚϯ͕ǁŝƚŚŽƵƚŝŶĐƵƌƌŝŶŐĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͘ŶĚǁŝƚŚŽƵƚĂĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͕ĂZĞƐƉŽŶƐŝďůĞŶƚŝƚLJĐĂŶŶŽƚƵƚŝůŝnjĞŝƚƐŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞǁŝƚŚŽƵƚǀŝŽůĂƚŝŶŐ
ƚŚĞEZ^ƚĂŶĚĂƌĚ>ͲϬϬϮ͘dŽƌĞƐŽůǀĞƚŚŝƐĐŽŶĨůŝĐƚ͕ƚŚĞĚƌĂĨƚŝŶŐƚĞĂŵĞůĞĐƚĞĚƚŽĂůůŽǁƚŚĞ
ZĞƐƉŽŶƐŝďůĞŶƚŝƚLJƚŽƵƐĞŝƚƐŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞǁŚŝůĞŝŶĂĚĞĐůĂƌĞĚŶĞƌŐLJŵĞƌŐĞŶĐLJůĞƌƚϮ
ŽƌŶĞƌŐLJŵĞƌŐĞŶĐLJůĞƌƚϯ͘
ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉZĞƉŽƌƚŝŶŐ
dŚĞĚƌĂĨƚŝŶŐƚĞĂŵĞůĞĐƚĞĚƚŽŝŶĐůƵĚĞƚŚŝƐĚĞĨŝŶŝƚŝŽŶƚŽƉƌŽǀŝĚĞĐůĂƌŝƚLJĨŽƌŵĞĂƐƵƌĞŵĞŶƚŽĨ
ĐŽŵƉůŝĂŶĐĞĨŽƌƚŚĞĂƉƉƌŽƉƌŝĂƚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͘ĚĚŝƚŝŽŶĂůůLJ͕ƚŚŝƐĚĞĨŝŶŝƚŝŽŶŝƐŶĞĐĞƐƐĂƌLJ
ƐŝŶĐĞƚŚĞĚƌĂĨƚŝŶŐƚĞĂŵŚĂƐĞůŝŵŝŶĂƚĞĚZϱ͘ϭĂŶĚZϱ͘ϮĨƌŽŵƚŚĞĞdžŝƐƚŝŶŐƐƚĂŶĚĂƌĚ͘Zϱ͘ϭĂŶĚZϱ͘Ϯ
ĂƌĞĚĞĨŝŶŝƚŝŽŶƐŵŝdžĞĚǁŝƚŚƉĞƌĨŽƌŵĂŶĐĞ͘dŚĞĚƌĂĨƚŝŶŐƚĞĂŵŚĂƐŝŶĐůƵĚĞĚĂůůƚŚĞƉĞƌĨŽƌŵĂŶĐĞ
ƌĞƋƵŝƌĞŵĞŶƚƐŝŶƚŚĞƉƌŽƉŽƐĞĚƐƚĂŶĚĂƌĚƐZϭĂŶĚZϮ͕ĂŶĚƚŚĞƌĞĨŽƌĞŵƵƐƚĂĚĚƚŚĞĚĞĨŝŶŝƚŝŽŶŽĨ
ƚŚĞZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉZĞƉŽƌƚŝŶŐ͘
KƚŚĞƌĞĨŝŶŝƚŝŽŶƐ
KƚŚĞƌĚĞĨŝŶŝƚŝŽŶƐŚĂǀĞďĞĞŶĂĚĚĞĚŽƌŵŽĚŝĨŝĞĚƚŽĂƐƐƵƌĞĐůĂƌŝĨŝĐĂƚŝŽŶǁŝƚŚŝŶƚŚĞƐƚĂŶĚĂƌĚĂŶĚ
ƌĞƋƵŝƌĞŵĞŶƚƐ͘


ZĂƚŝŽŶĂůĞďLJZĞƋƵŝƌĞŵĞŶƚ


ZĞƋƵŝƌĞŵĞŶƚϭ
dŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJĞdžƉĞƌŝĞŶĐŝŶŐĂZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐŚĂůů͕ǁŝƚŚŝŶ
ƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕ƌĞƚƵƌŶŝƚƐƚŽĂƚůĞĂƐƚ͗

o ĞƌŽ͕;ŝĨŝƚƐWƌĞͲZĞƉŽƌƚŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞǁĂƐƉŽƐŝƚŝǀĞŽƌĞƋƵĂůƚŽ
njĞƌŽͿ͕
o ůĞƐƐƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨĂůůƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJ
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ǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕ĂŶĚ
o ĨƵƌƚŚĞƌƌĞĚƵĐĞĚďLJƚŚĞŵĂŐŶŝƚƵĚĞŽĨƚŚĞĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶ;ŝͿƚŚĞ
ZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛ƐDŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;D^^ͿĂŶĚ;ŝŝͿƚŚĞƐƵŵ
ŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚĂůů
ƉƌĞǀŝŽƵƐĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚŚĂǀĞŶŽƚĐŽŵƉůĞƚĞĚƚŚĞŝƌ
ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚǁŚĞŶƚŚĞƐƵŵƌĞĨĞƌĞŶĐĞĚŝŶĐůĂƵƐĞ
;ŝŝͿŽĨƚŚŝƐďƵůůĞƚŝƐŐƌĞĂƚĞƌƚŚĂŶD^^͕
>ͲϬϬϮͲϮͲĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
:ƵůLJ͕ϮϬϭϯ

ϱ

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ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ^ƚĂŶĚĂƌĚĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
͕Žƌ
o

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ǀĞŶƚǁĂƐŶĞŐĂƚŝǀĞͿ͕
o ůĞƐƐƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨĂůůƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJ
ǀĞŶƚƐƚŚĂƚŽĐĐƵƌƉƌŝŽƌƚŽƚŚĂƚǀĂůƵĞŽĨZĞƉŽƌƚŝŶŐǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJ
ǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕ĂŶĚ
o &ƵƌƚŚĞƌƌĞĚƵĐĞĚďLJƚŚĞŵĂŐŶŝƚƵĚĞŽĨƚŚĞĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶ;ŝͿƚŚĞ
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ŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚĂůů
ƉƌĞǀŝŽƵƐĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚŚĂǀĞŶŽƚĐŽŵƉůĞƚĞĚƚŚĞŝƌ
ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚǁŚĞŶƚŚĞƐƵŵƌĞĨĞƌĞŶĐĞĚŝŶĐůĂƵƐĞ
;ŝŝͿŽĨƚŚŝƐďƵůůĞƚŝƐŐƌĞĂƚĞƌƚŚĂŶD^^

ϭ͘ϭ dŚĞƌĞƋƵŝƌĞĚƌĞƉŽƌƚŝŶŐĨŽƌŵŝƐZ&Žƌŵϭ͘
ϭ͘Ϯ͘ dŚŝƐƌĞƋƵŝƌĞŵĞŶƚ;ŝŶŝƚƐĞŶƚŝƌĞƚLJͿĚŽĞƐŶŽƚĂƉƉůLJǁŚĞŶƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ
ĞdžƉĞƌŝĞŶĐŝŶŐĂZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚŝƐĞdžƉĞƌŝĞŶĐŝŶŐĂŶŶĞƌŐLJ
ŵĞƌŐĞŶĐLJůĞƌƚ>ĞǀĞůϮŽƌ>ĞǀĞůϯ͘
ĂĐŬŐƌŽƵŶĚĂŶĚZĂƚŝŽŶĂůĞ
ZĞƋƵŝƌĞŵĞŶƚZϭƌĞĨůĞĐƚƐƚŚĞŽƉĞƌĂƚŝŶŐƉƌŝŶĐŝƉůĞƐĨŝƌƐƚĞƐƚĂďůŝƐŚĞĚďLJEZWŽůŝĐLJϭ͘/ƚƐ
ŽďũĞĐƚŝǀĞŝƐƚŽĂƐƐƵƌĞƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJďĂůĂŶĐĞƐƌĞƐŽƵƌĐĞƐĂŶĚĚĞŵĂŶĚĂŶĚƌĞƚƵƌŶƐŝƚƐ
ƌĞĂŽŶƚƌŽůƌƌŽƌ;ͿƚŽĚĞĨŝŶĞĚǀĂůƵĞƐ;ƐƵďũĞĐƚƚŽĂƉƉůŝĐĂďůĞůŝŵŝƚƐͿĨŽůůŽǁŝŶŐĂZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͘/ƚƌĞƋƵŝƌĞƐƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJƚŽƌĞĐŽǀĞƌĨƌŽŵĞǀĞŶƚƐƚŚĂƚ
ǁŽƵůĚďĞůĞƐƐƚŚĂŶŽƌĞƋƵĂůƚŽƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛ƐD^^͘/ƚĞƐƚĂďůŝƐŚĞƐĂĐĞŝůŝŶŐĨŽƌƚŚĞ
ĂŵŽƵŶƚŽĨŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĂŶĚƚŝŵĞĨƌĂŵĞƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJŵƵƐƚĚĞŵŽŶƐƚƌĂƚĞŝŶĂ
ĐŽŵƉůŝĂŶĐĞĞǀĂůƵĂƚŝŽŶ͘/ƚŝƐŝŶƚĞŶĚĞĚƚŽĞůŝŵŝŶĂƚĞƚŚĞĂŵďŝŐƵŝƚŝĞƐĂŶĚƋƵĞƐƚŝŽŶƐĂƐƐŽĐŝĂƚĞĚ
ǁŝƚŚƚŚĞĞdžŝƐƚŝŶŐƐƚĂŶĚĂƌĚ͘/ŶĂĚĚŝƚŝŽŶ͕ŝƚĂůůŽǁƐZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ;ƐͿƚŽŚĂǀĞĂĐůĞĂƌǁĂLJƚŽ
ĚĞŵŽŶƐƚƌĂƚĞĐŽŵƉůŝĂŶĐĞĂŶĚƐƵƉƉŽƌƚƚŚĞ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶƚŽƚŚĞĨƵůůĞdžƚĞŶƚŽĨD^^͘
LJŝŶĐůƵĚŝŶŐŶĞǁĚĞĨŝŶŝƚŝŽŶƐ͕ĂŶĚŵŽĚŝĨLJŝŶŐĞdžŝƐƚŝŶŐĚĞĨŝŶŝƚŝŽŶƐ͕ĂŶĚƚŚĞĂďŽǀĞZϭ͕ƚŚĞĚƌĂĨƚŝŶŐ
ƚĞĂŵďĞůŝĞǀĞƐŝƚŚĂƐƐƵĐĐĞƐƐĨƵůůLJĨƵůĨŝůůĞĚƚŚĞƌĞƋƵŝƌĞŵĞŶƚƐŽĨ&ZKƌĚĞƌEŽ͘ϲϵϯ;ĂƚWϯϱϲͿƚŽ
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ZĞƐĞƌǀĞ͘/ƚĂůƐŽƌĞĐŽŐŶŝnjĞƐƚŚĂƚƚŚĞůŽƐƐŽĨƚƌĂŶƐŵŝƐƐŝŽŶĂƐǁĞůůĂƐŐĞŶĞƌĂƚŝŽŶŵĂLJƌĞƋƵŝƌĞƚŚĞ
ĚĞƉůŽLJŵĞŶƚŽĨĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞ͘
ĚĚŝƚŝŽŶĂůůLJ͕ZϭŝƐĚĞƐŝŐŶĞĚƚŽĂƐƐƵƌĞƚŚĞĂƉƉůŝĐĂďůĞĞŶƚŝƚLJŵƵƐƚƵƐĞƌĞƐĞƌǀĞƚŽĐŽǀĞƌĂ
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ƚŚĂƚŚĂǀĞŽĐĐƵƌƌĞĚǁŝƚŚŝŶƚŚĞƐƉĞĐŝĨŝĞĚƉĞƌŝŽĚ͕ƚŽĂĚĚƌĞƐƐƚŚĞKƌĚĞƌ͛ƐĐŽŶĐĞƌŶƚŚĂƚƚŚĞ
ĂƉƉůŝĐĂďůĞĞŶƚŝƚLJŝƐƌĞƐƉŽŶĚŝŶŐƚŽĞǀĞŶƚƐĂŶĚƉĞƌĨŽƌŵĂŶĐĞŝƐŵĞĂƐƵƌĞĚ͘dŚĞZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĚĞĨŝŶŝƚŝŽŶ͕ĂůŽŶŐǁŝƚŚZϭĂůůŽǁƐĨŽƌŵĞĂƐƵƌĞŵĞŶƚŽĨƉĞƌĨŽƌŵĂŶĐĞ͘
dŚĞĚƌĂĨƚŝŶŐƚĞĂŵƵƐĞĚĚĂƚĂƐƵƉƉůŝĞĚďLJŽŶƐŽƌƚŝƵŵĨŽƌůĞĐƚƌŝĐZĞůŝĂďŝůŝƚLJdĞĐŚŶŽůŽŐLJ
^ŽůƵƚŝŽŶƐ;Zd^ͿƚŽŚĞůƉĚĞƚĞƌŵŝŶĞĂůůĞǀĞŶƚƐƚŚĂƚŚĂǀĞĂŶŝŵƉĂĐƚŽŶĨƌĞƋƵĞŶĐLJ͘ĂƚĂƚŚĂƚ
ǁĂƐĐŽŵƉŝůĞĚďLJZd^ƚŽƉƌŽǀŝĚĞŝŶĨŽƌŵĂƚŝŽŶŽŶŵĞĂƐƵƌĞĚĨƌĞƋƵĞŶĐLJĞǀĞŶƚƐŝƐƉƌĞƐĞŶƚĞĚŝŶ
>ͲϬϬϮͲϮͲĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
:ƵůLJ͕ϮϬϭϯ

ϲ

ŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ&ƌŽŵĂĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ^ƚĂŶĚĂƌĚĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
ƚƚĂĐŚŵĞŶƚϭ͘ŶĂůLJnjŝŶŐƚŚĞĚĂƚĂ͕ŽŶĞĐŽƵůĚĚĞŵŽŶƐƚƌĂƚĞĞǀĞŶƚƐŽĨϭϬϬDtŽƌŐƌĞĂƚĞƌǁŽƵůĚ
ĐĂƉƚƵƌĞĂůůĨƌĞƋƵĞŶĐLJĞǀĞŶƚƐĨŽƌĂůůŝŶƚĞƌĐŽŶŶĞĐƚŝŽŶƐ͘,ŽǁĞǀĞƌ͕ĂƚĂϭϬϬDtƌĞƉŽƌƚŝŶŐ
ƚŚƌĞƐŚŽůĚ͕ƚŚĞŶƵŵďĞƌŽĨĞǀĞŶƚƐƌĞƉŽƌƚĞĚǁŽƵůĚƐŝŐŶŝĨŝĐĂŶƚůLJŝŶĐƌĞĂƐĞǁŝƚŚŶŽƌĞůŝĂďŝůŝƚLJŐĂŝŶ
ƐŝŶĐĞϭϬϬDtŝƐŵŽƌĞƌĞĨůĞĐƚŝǀĞŽĨƚŚĞŽƵƚůLJŝŶŐĞǀĞŶƚƐ͕ĞƐƉĞĐŝĂůůLJŽŶůĂƌŐĞƌŝŶƚĞƌĐŽŶŶĞĐƚŝŽŶƐ͘
dŚĞŐŽĂůŽĨƚŚĞĚƌĂĨƚŝŶŐƚĞĂŵǁĂƐƚŽĚĞƐŝŐŶĂĐŽŶƚŝŶĞŶƚͲǁŝĚĞƐƚĂŶĚĂƌĚƚŽĐĂƉƚƵƌĞƚŚĞŵĂũŽƌŝƚLJ
ŽĨƚŚĞĞǀĞŶƚƐƚŚĂƚŝŵƉĂĐƚĨƌĞƋƵĞŶĐLJ͘ĨƚĞƌƌĞǀŝĞǁŝŶŐƚŚĞĚĂƚĂĂŶĚŝŶĚƵƐƚƌLJĐŽŵŵĞŶƚƐ͕ƚŚĞ
ĚƌĂĨƚŝŶŐƚĞĂŵĞůĞĐƚĞĚƚŽĞƐƚĂďůŝƐŚƌĞƉŽƌƚŝŶŐƚŚƌĞƐŚŽůĚŵŝŶŝŵƵŵƐĨŽƌĞĂĐŚƌĞƐƉĞĐƚŝǀĞ
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ƌĞƉŽƌƚĂďůĞƚŚƌĞƐŚŽůĚǁĂƐƐĞůĞĐƚĞĚĂƐƚŚĞůĞƐƐĞƌŽĨϴϬйŽĨƚŚĞĂƉƉůŝĐĂďůĞĞŶƚŝƚLJ;ƐͿDŽƐƚ^ĞǀĞƌĞ
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ĂƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶʹϵϬϬDt
tĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶʹϱϬϬDt
ZKdʹϴϬϬDt
YƵĞďĞĐʹϱϬϬDt

ĚĚŝƚŝŽŶĂůůLJ͕ƚŚĞĚƌĂĨƚŝŶŐƚĞĂŵŽŶůLJƵƐĞĚƚŚĞƉŽƐŝƚŝǀĞĞǀĞŶƚƐĨŽƌƉƵƌƉŽƐĞƐŽĨĚĞƚĞƌŵŝŶŝŶŐƚŚĞ
ĂďŽǀĞƚŚƌĞƐŚŽůĚƐ͘
sŝŽůĂƚŝŽŶ^ĞǀĞƌŝƚLJ>ĞǀĞůƐ
/ŶƚŚĞsŝŽůĂƚŝŽŶ^ĞǀĞƌŝƚLJ>ĞǀĞůƐĨŽƌZĞƋƵŝƌĞŵĞŶƚZϭ͕ƚŚĞŝŵƉĂĐƚŽĨƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ
ƌĞĐŽǀĞƌŝŶŐĨƌŽŵĂZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĚĞƉĞŶĚƐŽŶƚŚĞĂŵŽƵŶƚŽĨŝƚƐ
ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĂǀĂŝůĂďůĞĂŶĚĚŽĞƐŝƚŚĂǀĞƐƵĨĨŝĐŝĞŶƚƌĞƐƉŽŶƐĞ͘dŚĞs^>ƚĂŬĞƐƚŚĞƐĞĨĂĐƚŽƌƐ
ŝŶƚŽĂĐĐŽƵŶƚ͘
ŽŵƉůŝĂŶĐĞĂůĐƵůĂƚŝŽŶ
dŽĚĞƚĞƌŵŝŶĞĐŽŵƉůŝĂŶĐĞǁŝƚŚZϭ͕ƚŚĞƌĞƋƵŝƌĞĚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞĂŶĚŵĞĂƐƵƌĞĚ
ĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞĂƌĞĐŽŵƉƵƚĞĚĂŶĚĐŽŵƉĂƌĞĚĂƐĨŽůůŽǁƐ;ĂƐƐƵŵŝŶŐĂůů
ƌĞƐŽƵƌĐĞůŽƐƐǀĂůƵĞƐ͕ŝ͘Ğ͘ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐ͕ĂƌĞƉŽƐŝƚŝǀĞͿ͗
ͻ dŚĞƌĞƋƵŝƌĞĚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞĞƋƵĂůƐƚŚĞůĞƐƐĞƌŽĨƚŚĞŵĞŐĂǁĂƚƚ
ůŽƐƐŽĨƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͕ĂŶĚ͕ƚŚĞDŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞ
ŽŶƚŝŶŐĞŶĐLJŵŝŶƵƐƚŚĞƐƵŵŽĨƚŚĞŵĞŐĂǁĂƚƚůŽƐƐĞƐŽĨĂŶLJƉƌĞǀŝŽƵƐĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐǁŚŽƐĞƐƚĂƌƚƉƌĞĐĞĚĞĚƚŚĞƐƚĂƌƚŽĨƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚďLJůĞƐƐƚŚĂŶƚŚĞƐƵŵŽĨƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ
ĂŶĚŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚ͘
ͻ dŚĞŵĞĂƐƵƌĞĚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞŝƐĞƋƵĂůƚŽŽŶĞŽĨƚŚĞĨŽůůŽǁŝŶŐ͗
o /ĨƚŚĞWƌĞͲZĞƉŽƌƚĂďůĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞŝƐŐƌĞĂƚĞƌƚŚĂŶŽƌĞƋƵĂů
ƚŽnjĞƌŽ͕ƚŚĞŶƚŚĞŵĞĂƐƵƌĞĚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞĞƋƵĂůƐ;ĂͿƚŚĞ
ŵĞŐĂǁĂƚƚǀĂůƵĞŽĨƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƉůƵƐ;ďͿƚŚĞ
ŵŽƐƚƉŽƐŝƚŝǀĞǀĂůƵĞǁŝƚŚŝŶŝƚƐŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ;ĂŶĚ
ĨŽůůŽǁŝŶŐƚŚĞŽĐĐƵƌƌĞŶĐĞŽĨƚŚĞůĂƐƚƐƵďƐĞƋƵĞŶƚĞǀĞŶƚ͕ŝĨĂŶLJͿƉůƵƐ;ĐͿƚŚĞ
ƐƵŵŽĨƚŚĞŵĞŐĂǁĂƚƚůŽƐƐĞƐŽĨƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐ
>ͲϬϬϮͲϮͲĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
:ƵůLJ͕ϮϬϭϯ

ϳ

ŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ&ƌŽŵĂĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ^ƚĂŶĚĂƌĚĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
ŽĐĐƵƌƌŝŶŐǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚŽĨƚŚĞZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͘
o /ĨƚŚĞWƌĞͲZĞƉŽƌƚĂďůĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞŝƐůĞƐƐƚŚĂŶnjĞƌŽ͕ƚŚĞŶƚŚĞ
ŵĞĂƐƵƌĞĚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞĞƋƵĂůƐ;ĂͿƚŚĞŵĞŐĂǁĂƚƚǀĂůƵĞŽĨ
ƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƉůƵƐ;ďͿƚŚĞŵŽƐƚƉŽƐŝƚŝǀĞ
ǀĂůƵĞǁŝƚŚŝŶŝƚƐŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ;ĂŶĚĨŽůůŽǁŝŶŐƚŚĞ
ŽĐĐƵƌƌĞŶĐĞŽĨƚŚĞůĂƐƚƐƵďƐĞƋƵĞŶƚĞǀĞŶƚ͕ŝĨĂŶLJͿƉůƵƐ;ĐͿƚŚĞƐƵŵŽĨƚŚĞ
ŵĞŐĂǁĂƚƚůŽƐƐĞƐŽĨƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐŽĐĐƵƌƌŝŶŐ
ǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚŽĨƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͕ŵŝŶƵƐ;ĚͿƚŚĞWƌĞͲZĞƉŽƌƚĂďůĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
sĂůƵĞ͘
ͻ ŽŵƉůŝĂŶĐĞŝƐĐŽŵƉƵƚĞĚĂƐĨŽůůŽǁƐŽŶZ&ŽƌŵϭŝŶŽƌĚĞƌƚŽĚŽĐƵŵĞŶƚĂůů
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƵƐĞĚŝŶĐŽŵƉůŝĂŶĐĞĚĞƚĞƌŵŝŶĂƚŝŽŶ͗
o /ĨƚŚĞƌĞƋƵŝƌĞĚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞŝƐůĞƐƐƚŚĂŶŽƌĞƋƵĂůƚŽnjĞƌŽ͕
ƚŚĞŶƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚŽŵƉůŝĂŶĐĞĞƋƵĂůƐϭϬϬ
ƉĞƌĐĞŶƚ͘
o /ĨƚŚĞƌĞƋƵŝƌĞĚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞŝƐŐƌĞĂƚĞƌƚŚĂŶnjĞƌŽ͕
ƒ

ŶĚƚŚĞŵĞĂƐƵƌĞĚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞŝƐŐƌĞĂƚĞƌƚŚĂŶŽƌ
ĞƋƵĂůƚŽƚŚĞƌĞƋƵŝƌĞĚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞ͕ƚŚĞŶƚŚĞ
ZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚŽŵƉůŝĂŶĐĞĞƋƵĂůƐϭϬϬ
ƉĞƌĐĞŶƚ͘

ƒ

ŶĚƚŚĞŵĞĂƐƵƌĞĚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞŝƐůĞƐƐƚŚĂŶŽƌĞƋƵĂů
ƚŽnjĞƌŽ͕ƚŚĞŶƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚŽŵƉůŝĂŶĐĞ
ĞƋƵĂůƐϬƉĞƌĐĞŶƚ͘

ƒ

ŶĚƚŚĞŵĞĂƐƵƌĞĚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞŝƐůĞƐƐƚŚĂŶƚŚĞ
ƌĞƋƵŝƌĞĚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞďƵƚŐƌĞĂƚĞƌƚŚĂŶnjĞƌŽ͕ƚŚĞŶ
ƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚŽŵƉůŝĂŶĐĞĞƋƵĂůƐϭϬϬй
Ύ;ϭʹ;;ƌĞƋƵŝƌĞĚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞʹŵĞĂƐƵƌĞĚ
ĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞͿͬƌĞƋƵŝƌĞĚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞ
ƌĞƐƉŽŶƐĞͿͿ͘


dŚĞĂďŽǀĞĐŽŵƉƵƚĂƚŝŽŶƐĐĂŶďĞĞdžƉƌĞƐƐĞĚŵĂƚŚĞŵĂƚŝĐĂůůLJŝŶƚŚĞĨŽůůŽǁŝŶŐϳƐĞƋƵĞŶƚŝĂůƐƚĞƉƐ͕
ůĂďĞůĞĚĂƐ΀ϭͲϳ΁͕ǁŚĞƌĞ͗
ͺ^dʹŵŽƐƚƉŽƐŝƚŝǀĞĚƵƌŝŶŐƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚŽĐĐƵƌƌŝŶŐĂĨƚĞƌ
ƚŚĞůĂƐƚƐƵďƐĞƋƵĞŶƚĞǀĞŶƚ͕ŝĨĂŶLJ;DtͿ
ͺWZͲWƌĞͲZĞƉŽƌƚĂďůĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞ;DtͿ
KDW>/EͲZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚŽŵƉůŝĂŶĐĞƉĞƌĐĞŶƚĂŐĞ;ϬͲϭϬϬйͿ
>ͲϬϬϮͲϮͲĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
:ƵůLJ͕ϮϬϭϯ

ϴ

ŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ&ƌŽŵĂĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ^ƚĂŶĚĂƌĚĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
D^ͺZͺZ^WͲŵĞĂƐƵƌĞĚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞĨŽƌƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ;DtͿ
D^^ʹDŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;DtͿ
Dtͺ>K^dͲŵĞŐĂǁĂƚƚůŽƐƐŽĨƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ;DtͿ
ZYͺZͺZ^WʹƌĞƋƵŝƌĞĚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞĨŽƌƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ;DtͿ
^hDͺWZsͲƐƵŵŽĨƚŚĞŵĞŐĂǁĂƚƚůŽƐƐĞƐŽĨĂŶLJƉƌĞǀŝŽƵƐĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐǁŚŽƐĞ
ƐƚĂƌƚƉƌĞĐĞĚĞƐƚŚĞƐƚĂƌƚŽĨƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚďLJůĞƐƐƚŚĂŶƚŚĞƐƵŵŽĨ
ƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚĂŶĚŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚ;DtͿ
^hDͺ^h^YͲƐƵŵŽĨƚŚĞŵĞŐĂǁĂƚƚůŽƐƐĞƐŽĨƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐ
ŽĐĐƵƌƌŝŶŐǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚŽĨƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ;DtͿ

ZYͺZͺZ^WсŵŝŶŝŵƵŵŽĨDtͺ>K^d͕ĂŶĚ͕;D^^ʹ^hDͺWZsͿ΀ϭ΁
/ĨͺWZŝƐŐƌĞĂƚĞƌƚŚĂŶŽƌĞƋƵĂůƚŽϬ͕ƚŚĞŶ
D^ͺZͺZ^WсDtͺ>K^dнͺ^dн^hDͺ^h^Y΀Ϯ΁

/ĨͺWZŝƐůĞƐƐƚŚĂŶϬ͕ƚŚĞŶ
D^ͺZͺZ^WсDtͺ>K^dнͺ^dн^hDͺ^h^YʹͺWZ΀ϯ΁

/ĨZYͺZͺZ^WŝƐůĞƐƐƚŚĂŶŽƌĞƋƵĂůƚŽϬ͕ƚŚĞŶKDW>/EсϭϬϬ΀ϰ΁

/ĨZYͺZͺZ^WŝƐŐƌĞĂƚĞƌƚŚĂŶϬ͕ĂŶĚ͕
D^ͺZͺZ^WŝƐŐƌĞĂƚĞƌƚŚĂŶŽƌĞƋƵĂůƚŽZYͺZͺZ^W͕ƚŚĞŶ
KDW>/EсϭϬϬ΀ϱ΁

/ĨZYͺZͺZ^WŝƐŐƌĞĂƚĞƌƚŚĂŶϬ͕ĂŶĚ͕D^ͺZͺZ^WŝƐůĞƐƐƚŚĂŶŽƌĞƋƵĂůƚŽϬ͕ƚŚĞŶ
KDW>/EсϬ΀ϲ΁

/ĨZYͺZͺZ^WŝƐŐƌĞĂƚĞƌƚŚĂŶϬ͕ĂŶĚ͕D^ͺZͺZ^WŝƐŐƌĞĂƚĞƌƚŚĂŶϬ͕ĂŶĚ͕
D^ͺZͺZ^WŝƐůĞƐƐƚŚĂŶZYͺZͺZ^W͕ƚŚĞŶ
KDW>/EсϭϬϬΎ;ϭʹ;;ZYͺZͺZ^WʹD^ͺZͺZ^WͿͬZYͺZͺZ^WͿͿ΀ϳ΁
>ͲϬϬϮͲϮͲĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
:ƵůLJ͕ϮϬϭϯ

ϵ

ŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ&ƌŽŵĂĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ^ƚĂŶĚĂƌĚĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ


ZĞƋƵŝƌĞŵĞŶƚϮ
ZϮ͘džĐĞƉƚĚƵƌŝŶŐƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛ƐŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚĂŶĚƚŚĞ
ZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛ƐŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚ͕ŽƌĚƵƌŝŶŐĂŶŶĞƌŐLJ
ŵĞƌŐĞŶĐLJůĞƌƚ>ĞǀĞůϮŽƌϯĨŽƌƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJĂŶĚĨŽƌĂŶĂĚĚŝƚŝŽŶĂůĨŝǀĞ
ŚŽƵƌƐĚƵƌŝŶŐĂŐŝǀĞŶĐĂůĞŶĚĂƌƋƵĂƌƚĞƌ͕ƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJƐŚĂůůŵĂŝŶƚĂŝŶĂŶ
ĂŵŽƵŶƚŽĨŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĂƚůĞĂƐƚĞƋƵĂůƚŽŝƚƐDŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ͘
ĂĐŬŐƌŽƵŶĚĂŶĚZĂƚŝŽŶĂůĞ
ZϮĞƐƚĂďůŝƐŚĞƐĂƵŶŝĨŽƌŵĐŽŶƚŝŶĞŶƚͲǁŝĚĞĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƋƵŝƌĞŵĞŶƚ͘ZϮĞƐƚĂďůŝƐŚĞƐĂ
ƌĞƋƵŝƌĞŵĞŶƚƚŚĂƚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞďĞĂƚůĞĂƐƚĞƋƵĂůƚŽŝƚƐDŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ͘
LJŝŶĐůƵĚŝŶŐĂĚĞĨŝŶŝƚŝŽŶŽĨDŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJĂŶĚZϮ͕ĂĐŽŶƐŝƐƚĞŶƚƵŶŝĨŽƌŵ
ĐŽŶƚŝŶĞŶƚͲǁŝĚĞĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƋƵŝƌĞŵĞŶƚŚĂƐďĞĞŶĞƐƚĂďůŝƐŚĞĚ͘/ƚƐŐŽĂůŝƐƚŽĂƐƐƵƌĞ
ƚŚĂƚƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJǁŝůůŚĂǀĞƐƵĨĨŝĐŝĞŶƚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƚŚĂƚĐĂŶďĞĚĞƉůŽLJĞĚƚŽ
ŵĞĞƚZϭ͘
&ZKƌĚĞƌϲϵϯ;ĂƚWϯϱϲͿĚŝƌĞĐƚĞĚ>ͲϬϬϮďĞĚĞǀĞůŽƉĞĚĂƐĂĐŽŶƚŝŶĞŶƚͲǁŝĚĞĐŽŶƚŝŶŐĞŶĐLJ
ƌĞƐĞƌǀĞƉŽůŝĐLJ͘ZϮĨƵůĨŝůůƐƚŚĞƌĞƋƵŝƌĞŵĞŶƚĂƐƐŽĐŝĂƚĞĚǁŝƚŚƚŚĞƌĞƋƵŝƌĞĚĂŵŽƵŶƚŽĨĐŽŶƚŝŶŐĞŶĐLJ
ƌĞƐĞƌǀĞĂZĞƐƉŽŶƐŝďůĞŶƚŝƚLJŵƵƐƚŚĂǀĞĂǀĂŝůĂďůĞƚŽƌĞƐƉŽŶĚƚŽĂZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͘tŝƚŚŝŶ&ZKƌĚĞƌϲϵϯ;ĂƚWϯϯϲͿƚŚĞŽŵŵŝƐƐŝŽŶŶŽƚĞĚƚŚĂƚƚŚĞ
ĂƉƉƌŽƉƌŝĂƚĞŵŝdžŽĨŽƉĞƌĂƚŝŶŐƌĞƐĞƌǀĞ͕ƐƉŝŶŶŝŶŐƌĞƐĞƌǀĞĂŶĚŶŽŶͲƐƉŝŶŶŝŶŐƌĞƐĞƌǀĞƐŚŽƵůĚďĞ
ĂĚĚƌĞƐƐĞĚ͘,ŽǁĞǀĞƌ͕ƚŚĞKƌĚĞƌƉƌĞĚĂƚĞĚƚŚĞĂƉƉƌŽǀĂůŽĨƚŚĞŶĞǁ>ͲϬϬϯ͕ǁŚŝĐŚĂĚĚƌĞƐƐĞƐ
ĨƌĞƋƵĞŶĐLJƌĞƐƉŽŶƐŝǀĞƌĞƐĞƌǀĞĂŶĚƚŚĞĂŵŽƵŶƚŽĨĨƌĞƋƵĞŶĐLJƌĞƐƉŽŶƐĞŽďůŝŐĂƚŝŽŶ͘tŝƚŚƚŚĞ
ĚĞǀĞůŽƉŵĞŶƚŽĨ>ͲϬϬϯ͕ĂŶĚƚŚĞĂƐƐŽĐŝĂƚĞĚƌĞůŝĂďŝůŝƚLJƉĞƌĨŽƌŵĂŶĐĞƌĞƋƵŝƌĞŵĞŶƚ͕ƚŚĞĚƌĂĨƚŝŶŐ
ƚĞĂŵďĞůŝĞǀĞƐƚŚĂƚ͕ǁŝƚŚZϮŽĨ>ͲϬϬϮĂŶĚƚŚĞĂƉƉƌŽǀĂůŽĨ>ͲϬϬϯ͕ƚŚĞŽŵŵŝƐƐŝŽŶ͛ƐŐŽĂůƐŽĨ
ĂĐŽŶƚŝŶĞŶƚͲǁŝĚĞĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƐƉŽůŝĐLJŝƐŵĞƚ͘dŚĞƐƵŝƚĞƐŽĨ>ƐƚĂŶĚĂƌĚƐ;>ͲϬϬϭ͕
>ͲϬϬϮ͕ĂŶĚ>ͲϬϬϯͿĂƌĞĂůůƉĞƌĨŽƌŵĂŶĐĞͲďĂƐĞĚ͘tŝƚŚƚŚĞƐƵŝƚĞŽĨƐƚĂŶĚĂƌĚƐĂŶĚƚŚĞƐƉĞĐŝĨŝĐ
ƌĞƋƵŝƌĞŵĞŶƚƐǁŝƚŚŝŶĞĂĐŚƌĞƐƉĞĐƚŝǀĞƐƚĂŶĚĂƌĚ͕ĂĐŽŶƚŝŶĞŶƚͲǁŝĚĞĐŽŶƚŝŶŐĞŶĐLJƉŽůŝĐLJŝƐ
ĞƐƚĂďůŝƐŚĞĚ͘
/ŶƚŚĞsŝŽůĂƚŝŽŶ^ĞǀĞƌŝƚLJ>ĞǀĞůƐĨŽƌZĞƋƵŝƌĞŵĞŶƚZϭ͕ƚŚĞŝŵƉĂĐƚŽĨƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ
ƌĞĐŽǀĞƌŝŶŐĨƌŽŵĂZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĚĞƉĞŶĚƐŽŶƚŚĞĂŵŽƵŶƚŽĨŝƚƐ
ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĂǀĂŝůĂďůĞĂŶĚĚŽĞƐŝƚŚĂǀĞƐƵĨĨŝĐŝĞŶƚƌĞƐƉŽŶƐĞ͘ĚĚŝƚŝŽŶĂůůLJ͕ƚŚĞĚƌĂĨƚŝŶŐ
ƚĞĂŵƵŶĚĞƌƐƚĂŶĚƐƚŚĂƚZĞƐƉŽŶƐŝďůĞŶƚŝƚŝĞƐĂǀĂŝůĂďůĞŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞŵĂLJǀĂƌLJƐůŝŐŚƚůLJ
ĨƌŽŵD^^ĚƵƌŝŶŐĂŶLJƚŝŵĞŽĨƚŚĞLJĞĂƌ͘dŚƵƐ͕ƚŽĂůůŽǁĨŽƌƚŚĞĨŝǀĞŚŽƵƌƐŽĨĞdžĞŵƉƚŝŽŶďLJ
ĐĂůĞŶĚĂƌƋƵĂƌƚĞƌ͕ƚŚĞĚƌĂĨƚŝŶŐŵŽĚŝĨŝĞĚƚŚĞƌĞƋƵŝƌĞŵĞŶƚƚŽƌĞĨůĞĐƚƐƵĐŚĂŶĞdžĞŵƉƚŝŽŶ͘LJ
ŝŶĐůƵĚŝŶŐƚŚĞĞdžĞŵƉƚŝŽŶƉƌŽǀŝĚĞƐƚŚĞŶĞĐĞƐƐĂƌLJĐŽŶƚŝŶƵŝƚLJďĞƚǁĞĞŶƚŚĞƌĞƋƵŝƌĞŵĞŶƚĂŶĚƚŚĞ
s^>͘


>ͲϬϬϮͲϮͲĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
:ƵůLJ͕ϮϬϭϯ

ϭϬ

ŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵ
ŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ&ƌŽŵ
ŵĂĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶ
ŶĐLJǀĞŶƚ^ƚĂŶĚĂƌĚĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ

Attachment 1
NERC IInterconnections 2009
9-2012
Frequency
y Events Loss MW Sta
atistics

m
For: NERC BARC Standard Drafting Team
Prepared by: CERTS
Date: November 2, 2012


>ͲϬϬϮͲϮͲĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
:ƵůLJ͕ϮϬϭϯ

ϭϭ

ŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ&ƌŽŵĂĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ^ƚĂŶĚĂƌĚĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ

>ͲϬϬϮͲϮͲĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
:ƵůLJ͕ϮϬϭϯ

ϭϮ

ŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ&ƌŽŵĂĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ^ƚĂŶĚĂƌĚĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ

>ͲϬϬϮͲϮͲĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
:ƵůLJ͕ϮϬϭϯ

ϭϯ

ŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ&ƌŽŵĂĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ^ƚĂŶĚĂƌĚĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ

>ͲϬϬϮͲϮͲĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
:ƵůLJ͕ϮϬϭϯ

ϭϰ

ŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ&ƌŽŵĂĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ^ƚĂŶĚĂƌĚĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ



>ͲϬϬϮͲϮͲĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
:ƵůLJ͕ϮϬϭϯ

ϭϱ




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ŽŶƚĞŶƚƐ
Table of Contents ............................................................................................................................ 2
/ŶƚƌŽĚƵĐƚŝŽŶ .................................................................................................................................... 3
Requirement 1 ................................................................................................................................. 5
Requirement 2 ............................................................................................................................. 109

>ͲϬϬϮͲϮͲĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
:ƵůLJ͕ϮϬϭϯ

Ϯ

ŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ&ƌŽŵĂĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ^ƚĂŶĚĂƌĚĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ

/ŶƚƌŽĚƵĐƚŝŽŶ
dŚĞƌĞǀŝƐŝŽŶƚŽEZWŽůŝĐLJ^ƚĂŶĚĂƌĚƐŝŶϭϵϵϲĐƌĞĂƚĞĚĂŝƐƚƵƌďĂŶĐĞŽŶƚƌŽů^ƚĂŶĚĂƌĚ;^Ϳ͘
/ƚdŚĞLJƌĞƉůĂĐĞĚϭ;ƌĞĂŽŶƚƌŽůƌƌŽƌ;ͿƌĞƚƵƌŶƚŽnjĞƌŽǁŝƚŚŝŶϭϬŵŝŶƵƚĞƐĨŽůůŽǁŝŶŐĂ
ĚŝƐƚƵƌďĂŶĐĞͿĂŶĚϮ;ŵƵƐƚƐƚĂƌƚƚŽƌĞƚƵƌŶƚŽnjĞƌŽŝŶϭŵŝŶƵƚĞĨŽůůŽǁŝŶŐĂĚŝƐƚƵƌďĂŶĐĞͿǁŝƚŚ
ĂƐƚĂŶĚĂƌĚƚŚĂƚƐƚĂƚĞƐ͗ŵƵƐƚƌĞƚƵƌŶƚŽĞŝƚŚĞƌnjĞƌŽŽƌĂƉƌĞͲĚŝƐƚƵƌďĂŶĐĞǀĂůƵĞŽĨǁŝƚŚŝŶ
ϭϱͲŵŝŶƵƚĞƐĨŽůůŽǁŝŶŐĂƌĞƉŽƌƚĂďůĞĚŝƐƚƵƌďĂŶĐĞ͘ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐĂƌĞƌĞƋƵŝƌĞĚƚŽƌĞƉŽƌƚĂůů
ĚŝƐƚƵƌďĂŶĐĞƐĞƋƵĂůƚŽŽƌŐƌĞĂƚĞƌƚŚĂŶϴϬйŽĨƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛ƐŵŽƐƚƐĞǀĞƌĞƐŝŶŐůĞ
ĐŽŶƚŝŶŐĞŶĐLJ͘

>ͲϬϬϮǁĂƐĐƌĞĂƚĞĚƚŽƌĞƉůĂĐĞƉŽƌƚŝŽŶƐŽĨWŽůŝĐLJϭ͘/ƚŵĞĂƐƵƌĞƐƚŚĞĂďŝůŝƚLJŽĨĂŶĂƉƉůŝĐĂďůĞ
ĞŶƚŝƚLJƚŽƌĞĐŽǀĞƌĨƌŽŵĂƌĞƉŽƌƚĂďůĞĞǀĞŶƚǁŝƚŚƚŚĞĚĞƉůŽLJŵĞŶƚŽĨƌĞƐĞƌǀĞ͘dŚĞƌĞůŝĂďůĞ
ŽƉĞƌĂƚŝŽŶŽĨƚŚĞŝŶƚĞƌĐŽŶŶĞĐƚĞĚƉŽǁĞƌƐLJƐƚĞŵƌĞƋƵŝƌĞƐƚŚĂƚĂĚĞƋƵĂƚĞŐĞŶĞƌĂƚŝŶŐĐĂƉĂĐŝƚLJďĞ
ĂǀĂŝůĂďůĞĂƚĂůůƚŝŵĞƐƚŽŵĂŝŶƚĂŝŶƐĐŚĞĚƵůĞĚĨƌĞƋƵĞŶĐLJĂŶĚĂǀŽŝĚůŽƐƐŽĨĨŝƌŵůŽĂĚĨŽůůŽǁŝŶŐůŽƐƐ
ŽĨƚƌĂŶƐŵŝƐƐŝŽŶŽƌŐĞŶĞƌĂƚŝŽŶĐŽŶƚŝŶŐĞŶĐŝĞƐ͘dŚŝƐŐĞŶĞƌĂƚŝŶŐĐĂƉĂĐŝƚLJŝƐŶĞĐĞƐƐĂƌLJƚŽƌĞƉůĂĐĞ
ŐĞŶĞƌĂƚŝŶŐĐĂƉĂĐŝƚLJĂŶĚĞŶĞƌŐLJůŽƐƚĚƵĞƚŽĨŽƌĐĞĚŽƵƚĂŐĞƐŽĨŐĞŶĞƌĂƚŝŽŶŽƌƚƌĂŶƐŵŝƐƐŝŽŶ
ĞƋƵŝƉŵĞŶƚ͘

dŚŝƐĚŽĐƵŵĞŶƚƉƌŽǀŝĚĞƐďĂĐŬŐƌŽƵŶĚŽŶƚŚĞĚĞǀĞůŽƉŵĞŶƚĂŶĚŝŵƉůĞŵĞŶƚĂƚŝŽŶŽĨ>ͲϬϬϮͲϮͲ
ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͘dŚŝƐĚŽĐƵŵĞŶƚĞdžƉůĂŝŶƐ
ƚŚĞƌĂƚŝŽŶĂůĞĂŶĚĐŽŶƐŝĚĞƌĂƚŝŽŶƐĨŽƌƚŚĞƌĞƋƵŝƌĞŵĞŶƚƐĂŶĚƚŚĞŝƌĂƐƐŽĐŝĂƚĞĚĐŽŵƉůŝĂŶĐĞ
ŝŶĨŽƌŵĂƚŝŽŶ͘>ͲϬϬϮͲϮǁĂƐĚĞǀĞůŽƉĞĚƚŽĨƵůĨŝůůƚŚĞEZĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJŽŶƚƌŽůƐ;WƌŽũĞĐƚ
ϮϬϬϳͲϬϱͿ^ƚĂŶĚĂƌĚƵƚŚŽƌŝnjĂƚŝŽŶZĞƋƵĞƐƚ;^ZͿ͕ǁŚŝĐŚŝŶĐůƵĚĞƐƚŚĞŝŶĐŽƌƉŽƌĂƚŝŽŶŽĨƚŚĞ&Z
KƌĚĞƌϲϵϯĚŝƌĞĐƚŝǀĞƐ͘dŚĞŽƌŝŐŝŶĂů^Z͕ĂƉƉƌŽǀĞĚďLJƚŚĞŝŶĚƵƐƚƌLJ͕ƉƌĞƐƵŵĞƐƚŚĞƌĞŝƐƉƌĞƐĞŶƚůLJ
ƐƵĨĨŝĐŝĞŶƚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞŝŶĂůůƚŚĞEŽƌƚŚŵĞƌŝĐĂŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶƐ͘dŚĞƵŶĚĞƌůLJŝŶŐŐŽĂů
ŽĨƚŚĞ^ZǁĂƐƚŽƵƉĚĂƚĞƚŚĞƐƚĂŶĚĂƌĚƚŽŵĂŬĞƚŚĞŵĞĂƐƵƌĞŵĞŶƚƉƌŽĐĞƐƐŵŽƌĞŽďũĞĐƚŝǀĞĂŶĚ
ƚŽƉƌŽǀŝĚĞŝŶĨŽƌŵĂƚŝŽŶƚŽƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJŽƌZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ͕ƐƵĐŚƚŚĂƚƚŚĞ
ƉĂƌƚŝĞƐǁŽƵůĚďĞƚƚĞƌƵŶĚĞƌƐƚĂŶĚƚŚĞƵƐĞŽĨŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞƚŽďĂůĂŶĐĞƌĞƐŽƵƌĐĞƐĂŶĚ
ĚĞŵĂŶĚĨŽůůŽǁŝŶŐĂZĞƉŽƌƚĂďůĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͘ƵƌƌĞŶƚůLJ͕ƚŚĞĞdžŝƐƚŝŶŐ>ͲϬϬϮͲϭƐƚĂŶĚĂƌĚ
ĐŽŶƚĂŝŶƐZĞƋƵŝƌĞŵĞŶƚƐƐƉĞĐŝĨŝĐƚŽĂZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉǁŚŝĐŚƚŚĞĚƌĂĨƚŝŶŐƚĞĂŵďĞůŝĞǀĞƐ
ĂƌĞĐŽŵŵĞƌĐŝĂůŝŶŶĂƚƵƌĞĂŶĚŝƐĂĐŽŶƚƌĂĐƚƵĂůĂƌƌĂŶŐĞŵĞŶƚďĞƚǁĞĞŶƚŚĞƌĞƐĞƌǀĞƐŚĂƌŝŶŐŐƌŽƵƉ
ƉĂƌƚŝĞƐ͘>ͲϬϬϮͲϮŝƐŝŶƚĞŶĚĞĚƚŽŵĞĂƐƵƌĞƚŚĞƐƵĐĐĞƐƐĨƵůĚĞƉůŽLJŵĞŶƚŽĨĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞ
ďLJƌĞƐƉŽŶƐŝďůĞĞŶƚŝƚŝĞƐ͘ZĞůĂƚŝŽŶƐŚŝƉƐďĞƚǁĞĞŶƚŚĞĞŶƚŝƚŝĞƐƐŚŽƵůĚŶŽƚďĞƉĂƌƚŽĨƚŚĞ
ƉĞƌĨŽƌŵĂŶĐĞƌĞƋƵŝƌĞŵĞŶƚƐ͕ďƵƚůĞĨƚƵƉƚŽĂĐŽŵŵĞƌĐŝĂůƚƌĂŶƐĂĐƚŝŽŶ͘

ůĂƌŝƚLJĂŶĚƐƉĞĐŝĨŝĐƐĂƌĞƉƌŽǀŝĚĞĚǁŝƚŚƐĞǀĞƌĂůŶĞǁĚĞĨŝŶŝƚŝŽŶƐ͘ĚĚŝƚŝŽŶĂůůLJ͕ƚŚĞ>ͲϬϬϮͲϮ
ĞůŝŵŝŶĂƚĞƐĂŶLJƋƵĞƐƚŝŽŶŽŶǁŚŽŝƐƚŚĞĂƉƉůŝĐĂďůĞĞŶƚŝƚLJĂŶĚĂƐƐƵƌĞƐƚŚĞĂƉƉůŝĐĂďůĞĞŶƚŝƚLJŝƐŚĞůĚ
ƌĞƐƉŽŶƐŝďůĞĨŽƌƚŚĞƉĞƌĨŽƌŵĂŶĐĞƌĞƋƵŝƌĞŵĞŶƚ͘dŚĞĚƌĂĨƚŝŶŐƚĞĂŵ͛ƐŐŽĂůǁĂƐƚŽŚĂǀĞ>ͲϬϬϮͲϮ
ƐŽůĞůLJĂƉĞƌĨŽƌŵĂŶĐĞƐƚĂŶĚĂƌĚ͘dŚĞƉƌŝŵĂƌLJŽďũĞĐƚŝǀĞŽĨ>ͲϬϬϮͲϮŝƐƚŽĂƐƐƵƌĞƚŚĞĂƉƉůŝĐĂďůĞ
>ͲϬϬϮͲϮͲĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
:ƵůLJ͕ϮϬϭϯ

ϯ

ŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ&ƌŽŵĂĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ^ƚĂŶĚĂƌĚĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
ĞŶƚŝƚLJďĂůĂŶĐĞƐƌĞƐŽƵƌĐĞƐĂŶĚĚĞŵĂŶĚĂŶĚƌĞƚƵƌŶƐŝƚƐƌĞĂŽŶƚƌŽůƌƌŽƌƚŽĚĞĨŝŶĞĚǀĂůƵĞƐ
;ƐƵďũĞĐƚƚŽĂƉƉůŝĐĂďůĞůŝŵŝƚƐͿĨŽůůŽǁŝŶŐĂZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͘


ĂĐŬŐƌŽƵŶĚ

dŚŝƐƐĞĐƚŝŽŶĚŝƐĐƵƐƐĞƐƚŚĞŶĞǁĚĞĨŝŶŝƚŝŽŶƐĂƐƐŽĐŝĂƚĞĚǁŝƚŚ>ͲϬϬϮͲϮ͘
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
dŚĞƉƵƌƉŽƐĞŽĨ>ͲϬϬϮͲϮŝƐƚŽĞŶƐƵƌĞƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJŽƌZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ
ďĂůĂŶĐĞƌĞƐŽƵƌĐĞƐĂŶĚĚĞŵĂŶĚďLJƌĞƚƵƌŶŝŶŐŝƚƐƌĞĂŽŶƚƌŽůƌƌŽƌƚŽĚĞĨŝŶĞĚǀĂůƵĞƐĨŽůůŽǁŝŶŐĂ
ZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͘
dŚĞĚƌĂĨƚŝŶŐƚĞĂŵŝŶĐůƵĚĞĚĂƐƉĞĐŝĨŝĐĚĞĨŝŶŝƚŝŽŶĨŽƌĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƚŽĞůŝŵŝŶĂƚĞ
ĂŶLJĐŽŶĨƵƐŝŽŶĂŶĚĂŵďŝŐƵŝƚLJ͘dŚĞƉƌŝŽƌǀĞƌƐŝŽŶŽĨ>ͲϬϬϮǁĂƐďƌŽĂĚĂŶĚĐŽƵůĚďĞŝŶƚĞƌƉƌĞƚĞĚ
ŝŶǀĂƌŝŽƵƐŵĂŶŶĞƌƐůĞĂǀŝŶŐƚŚĞĂďŝůŝƚLJƚŽŵĞĂƐƵƌĞĐŽŵƉůŝĂŶĐĞƵƉƚŽƚŚĞĞLJĞŽĨƚŚĞďĞŚŽůĚĞƌ͘LJ
ŝŶĐůƵĚŝŶŐƚŚĞƐƉĞĐŝĨŝĐĚĞĨŝŶŝƚŝŽŶ͕ŝƚĂůůŽǁƐƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJƚŽĨƵůůLJƵŶĚĞƌƐƚĂŶĚŚŽǁƚŽ
ƉĞƌĨŽƌŵĂŶĚŵĞĞƚĐŽŵƉůŝĂŶĐĞ͘ůƐŽ͕&ZKƌĚĞƌϲϵϯ;ĂƚWϯϱϱͿĚŝƌĞĐƚĞĚĞŶƚŝƚŝĞƐƚŽŝŶĐůƵĚĞĂ
ZĞƋƵŝƌĞŵĞŶƚƚŚĂƚŵĞĂƐƵƌĞƐƌĞƐƉŽŶƐĞĨŽƌĂŶLJĞǀĞŶƚŽƌĐŽŶƚŝŶŐĞŶĐLJƚŚĂƚĐĂƵƐĞƐĂĨƌĞƋƵĞŶĐLJ
ĚĞǀŝĂƚŝŽŶ͘LJĚĞǀĞůŽƉŝŶŐĂƐƉĞĐŝĨŝĐĚĞĨŝŶŝƚŝŽŶƚŚĂƚĚĞƉŝĐƚƐƚŚĞĞǀĞŶƚƐĐĂƵƐŝŶŐĂŶƵŶĞdžƉĞĐƚĞĚ
ĐŚĂŶŐĞƚŽƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛Ɛ͕ĂŶĚƚŚĞŶĞĐĞƐƐĂƌLJƌĞƋƵŝƌĞŵĞŶƚƐĂƐƐƵƌĞƐ&Z͛Ɛ
ƌĞƋƵŝƌĞŵĞŶƚŝƐŵĞƚ͘
DŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ
dŚĞDŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;D^^ͿƚĞƌŵŚĂƐďĞĞŶǁŝĚĞůLJƵƐĞĚǁŝƚŚŝŶƚŚĞ
ŝŶĚƵƐƚƌLJ͕ŝŶĚƵƐƚƌLJ͖ŚŽǁĞǀĞƌ͕ŝƚŚĂƐŶĞǀĞƌďĞĞŶĚĞĨŝŶĞĚ͘/ŶŽƌĚĞƌƚŽĞůŝŵŝŶĂƚĞĂǁŝĚĞƌĂŶŐĞŽĨ
ĚĞĨŝŶŝƚŝŽŶƐ͕ƚŚĞĚƌĂĨƚŝŶŐƚĞĂŵŚĂƐŝŶĐůƵĚĞĚĂƐƉĞĐŝĨŝĐĚĞĨŝŶŝƚŝŽŶĚĞƐŝŐŶĞĚƚŽĨƵůĨŝůůƚŚĞŶĞĞĚƐŽĨ
ƚŚĞƐƚĂŶĚĂƌĚ͘/ŶĂĚĚŝƚŝŽŶ͕ŝŶŽƌĚĞƌƚŽŵĞĞƚ&ZKƌĚĞƌEŽ͘ϲϵϯ;ĂƚWϯϱϲͿ͕ƚŽĚĞǀĞůŽƉĂ
ĐŽŶƚŝŶĞŶƚͲǁŝĚĞĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƉŽůŝĐLJ͕ŝƚǁĂƐŶĞĐĞƐƐĂƌLJƚŽĞƐƚĂďůŝƐŚĂĚĞĨŝŶŝƚŝŽŶĨŽƌD^^͘
ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ
DŽƐƚƐLJƐƚĞŵŽƉĞƌĂƚŽƌƐŐĞŶĞƌĂůůLJŚĂǀĞĂŐŽŽĚƵŶĚĞƌƐƚĂŶĚŝŶŐŽĨƚŚĞŶĞĞĚƚŽďĂůĂŶĐĞƌĞƐŽƵƌĐĞƐ
ĂŶĚĚĞŵĂŶĚĂŶĚƌĞƚƵƌŶƚŚĞŝƌŝƚƐƌĞĂŽŶƚƌŽůƌƌŽƌƚŽĚĞĨŝŶĞĚǀĂůƵĞƐĨŽůůŽǁŝŶŐĂZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͘,ŽǁĞǀĞƌ͕ƚŚĞĞdžŝƐƚŝŶŐĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞĚĞĨŝŶŝƚŝŽŶƐƉƌŝŵĂƌŝůLJ
ĨŽĐƵƐĞĚŽŶŐĞŶĞƌĂƚŝŽŶĂŶĚŶŽƚĚĞŵĂŶĚƐŝĚĞŵĂŶĂŐĞŵĞŶƚ͘/ŶŽƌĚĞƌƚŽŵĞĞƚ&ZKƌĚĞƌEŽ͘
ϲϵϯ;ĂƚWϯϱϲͿƚŽŝŶĐůƵĚĞĂZĞƋƵŝƌĞŵĞŶƚƚŚĂƚĞdžƉůŝĐŝƚůLJĂůůŽǁƐĚĞŵĂŶĚͲƐŝĚĞŵĂŶĂŐĞŵĞŶƚ;^DͿ
ƚŽďĞƵƐĞĚĂƐĂƌĞƐŽƵƌĐĞĨŽƌĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞ͕ƚŚĞĚƌĂĨƚŝŶŐƚĞĂŵĞůĞĐƚĞĚƚŽĞdžƉĂŶĚƚŚĞ
ĚĞĨŝŶŝƚŝŽŶŽĨŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞƚŽĞdžƉůŝĐŝƚůLJŝŶĐůƵĚĞĐĂƉĂĐŝƚLJĂƐƐŽĐŝĂƚĞĚǁŝƚŚĚĞŵĂŶĚƐŝĚĞ
ŵĂŶĂŐĞŵĞŶƚ͘
ĚĚŝƚŝŽŶĂůůLJ͕ĐŽŶĨůŝĐƚĞdžŝƐƚĞĚďĞƚǁĞĞŶ>ͲϬϬϮĂŶĚKWͲϬϬϮĂƐƚŽǁŚĞŶĂŶĞŶƚŝƚLJĐŽƵůĚĚĞƉůŽLJ
ŝƚƐĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞ͘dŽĞůŝŵŝŶĂƚĞƚŚĞƉŽƐƐŝďůĞĐŽŶĨůŝĐƚĂŶĚƚŽĂƐƐƵƌĞ>ͲϬϬϮĂŶĚKWͲϬϬϮ
ǁŽƌŬƚŽŐĞƚŚĞƌĂŶĚĐŽŵƉůŝŵĞŶƚĞĚĞĂĐŚŽƚŚĞƌ͕ƚŚĞĚƌĂĨƚŝŶŐƚĞĂŵĐůĂƌŝĨŝĞĚƚŚĞĞdžŝƐƚŝŶŐĚĞĨŝŶŝƚŝŽŶ
>ͲϬϬϮͲϮͲĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
:ƵůLJ͕ϮϬϭϯ

ϰ

ŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ&ƌŽŵĂĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ^ƚĂŶĚĂƌĚĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
ŽĨŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ͘dŚĞĐŽŶĨůŝĐƚĂƌŝƐĞƐƐŝŶĐĞƚŚĞĂĐƚŝŽŶƐƌĞƋƵŝƌĞĚďLJŶĞƌŐLJĞĨŝĐŝĞŶƚ
ŶƚŝƚŝĞƐďĞĨŽƌĞĚĞĐůĂƌŝŶŐĞŝƚŚĞƌĂŶŶĞƌŐLJŵĞƌŐĞŶĐLJůĞƌƚϮŽƌĂŶŶĞƌŐLJŵĞƌŐĞŶĐLJůĞƌƚϯ
ƌĞƋƵŝƌĞƐĚĞƉůŽLJŵĞŶƚŽĨĂůůKƉĞƌĂƚŝŶŐƌĞƐĞƌǀĞǁŚŝĐŚŝŶĐůƵĚĞƐŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ͘ŶŶĞƌŐLJ
ĞĨŝĐŝĞŶƚŶƚŝƚLJŵĂLJŶĞĞĚƚŽĚĞĐůĂƌĞĞŝƚŚĞƌĂŶŶĞƌŐLJŵĞƌŐĞŶĐLJůĞƌƚϮŽƌĂŶŶĞƌŐLJ
ŵĞƌŐĞŶĐLJůĞƌƚϯ͕ǁŝƚŚŽƵƚŝŶĐƵƌƌŝŶŐĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͘ŶĚǁŝƚŚŽƵƚĂĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͕ĂZĞƐƉŽŶƐŝďůĞŶƚŝƚLJĐĂŶŶŽƚƵƚŝůŝnjĞŝƚƐŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞǁŝƚŚŽƵƚǀŝŽůĂƚŝŶŐ
ƚŚĞEZ^ƚĂŶĚĂƌĚ>ͲϬϬϮ͘dŽƌĞƐŽůǀĞƚŚŝƐĐŽŶĨůŝĐƚ͕ƚŚĞĚƌĂĨƚŝŶŐƚĞĂŵĞůĞĐƚĞĚƚŽĂůůŽǁƚŚĞ
ZĞƐƉŽŶƐŝďůĞŶƚŝƚLJƚŽƵƐĞŝƚƐŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞǁŚŝůĞŝŶĂĚĞĐůĂƌĞĚŶĞƌŐLJŵĞƌŐĞŶĐLJůĞƌƚϮ
ŽƌŶĞƌŐLJŵĞƌŐĞŶĐLJůĞƌƚϯ͘
ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉZĞƉŽƌƚŝŶŐ
dŚĞĚƌĂĨƚŝŶŐƚĞĂŵĞůĞĐƚĞĚƚŽŝŶĐůƵĚĞƚŚŝƐĚĞĨŝŶŝƚŝŽŶƚŽƉƌŽǀŝĚĞĐůĂƌŝƚLJĨŽƌŵĞĂƐƵƌĞŵĞŶƚŽĨ
ĐŽŵƉůŝĂŶĐĞĨŽƌƚŚĞĂƉƉƌŽƉƌŝĂƚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͘ĚĚŝƚŝŽŶĂůůLJ͕ƚŚŝƐĚĞĨŝŶŝƚŝŽŶŝƐŶĞĐĞƐƐĂƌLJ
ƐŝŶĐĞƚŚĞĚƌĂĨƚŝŶŐƚĞĂŵŚĂƐĞůŝŵŝŶĂƚĞĚZϱ͘ϭĂŶĚZϱ͘ϮĨƌŽŵƚŚĞĞdžŝƐƚŝŶŐƐƚĂŶĚĂƌĚ͘Zϱ͘ϭĂŶĚZϱ͘Ϯ
ĂƌĞĚĞĨŝŶŝƚŝŽŶƐŵŝdžĞĚǁŝƚŚƉĞƌĨŽƌŵĂŶĐĞ͘dŚĞĚƌĂĨƚŝŶŐƚĞĂŵŚĂƐŝŶĐůƵĚĞĚĂůůƚŚĞƉĞƌĨŽƌŵĂŶĐĞ
ƌĞƋƵŝƌĞŵĞŶƚƐŝŶƚŚĞƉƌŽƉŽƐĞĚƐƚĂŶĚĂƌĚƐZϭĂŶĚZϮ͕ĂŶĚƚŚĞƌĞĨŽƌĞŵƵƐƚĂĚĚƚŚĞĚĞĨŝŶŝƚŝŽŶŽĨ
ƚŚĞZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉZĞƉŽƌƚŝŶŐ͘
KƚŚĞƌĞĨŝŶŝƚŝŽŶƐ
KƚŚĞƌĚĞĨŝŶŝƚŝŽŶƐŚĂǀĞďĞĞŶĂĚĚĞĚŽƌŵŽĚŝĨŝĞĚƚŽĂƐƐƵƌĞĐůĂƌŝĨŝĐĂƚŝŽŶǁŝƚŚŝŶƚŚĞƐƚĂŶĚĂƌĚĂŶĚ
ƌĞƋƵŝƌĞŵĞŶƚƐ͘


ZĂƚŝŽŶĂůĞďLJZĞƋƵŝƌĞŵĞŶƚ


ZĞƋƵŝƌĞŵĞŶƚϭ
džĐĞƉƚǁŚĞŶĂŶŶĞƌŐLJŵĞƌŐĞŶĐLJůĞƌƚ>ĞǀĞůϮŽƌ>ĞǀĞůϯŝƐŝŶĞĨĨĞĐƚ͕ƚdŚĞZĞƐƉŽŶƐŝďůĞ
ŶƚŝƚLJĞdžƉĞƌŝĞŶĐŝŶŐĂZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐŚĂůů͕ĚĞŵŽŶƐƚƌĂƚĞ
ƚŚĂƚǁŝƚŚŝŶƚŚĞ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕ƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJƌĞƚƵƌŶĞĚŝƚƐƚŽĂƚůĞĂƐƚ͗

o ĞƌŽ͕;ŝĨŝƚƐWƌĞͲZĞƉŽƌƚŝŶŐĂďůĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞǁĂƐƉŽƐŝƚŝǀĞŽƌĞƋƵĂů
ƚŽnjĞƌŽͿ͕
o ůĞƐƐƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨĂůůƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJ
ǀĞŶƚƐƚŚĂƚŽĐĐƵƌƉƌŝŽƌƚŽƚŚĂƚǀĂůƵĞŽĨZĞƉŽƌƚŝŶŐĐĞǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJ
ǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕ĂŶĚ
o ĨƵƌƚŚĞƌƌĞĚƵĐĞĚďLJƚŚĞŵĂŐŶŝƚƵĚĞŽĨƚŚĞĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶ;ŝͿƚŚĞ
ZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛ƐDŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;D^^ͿĂŶĚ;ŝŝͿƚŚĞƐƵŵ
ŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚĂůů
ƉƌĞǀŝŽƵƐĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚŚĂǀĞŶŽƚĐŽŵƉůĞƚĞĚƚŚĞŝƌ
>ͲϬϬϮͲϮͲĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
:ƵůLJ͕ϮϬϭϯ

ϱ

ŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ&ƌŽŵĂĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ^ƚĂŶĚĂƌĚĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚǁŚĞŶƚŚĞƐƵŵƌĞĨĞƌĞŶĐĞĚŝŶĐůĂƵƐĞ
;ŝŝͿŽĨƚŚŝƐďƵůůĞƚŝƐŐƌĞĂƚĞƌƚŚĂŶD^^͕
͕Žƌ
o

/ƚƐWƌĞͲZĞƉŽƌƚŝŶŐĂďůĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞ͕;ŝĨŝƚƐWƌĞͲZĞƉŽƌƚŝŶŐĂďůĞ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚǁĂƐŶĞŐĂƚŝǀĞͿ͕
o ůĞƐƐƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨĂůůƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJ
ǀĞŶƚƐƚŚĂƚŽĐĐƵƌƉƌŝŽƌƚŽƚŚĂƚǀĂůƵĞŽĨZĞƉŽƌƚŝŶŐǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJ
ǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕ĂŶĚ
o &ƵƌƚŚĞƌƌĞĚƵĐĞĚďLJƚŚĞŵĂŐŶŝƚƵĚĞŽĨƚŚĞĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶ;ŝͿƚŚĞ
ZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛ƐDŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;D^^ͿĂŶĚ;ŝŝͿƚŚĞƐƵŵ
ŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚĂůů
ƉƌĞǀŝŽƵƐĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚŚĂǀĞŶŽƚĐŽŵƉůĞƚĞĚƚŚĞŝƌ
ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚǁŚĞŶƚŚĞƐƵŵƌĞĨĞƌĞŶĐĞĚŝŶĐůĂƵƐĞ
;ŝŝͿŽĨƚŚŝƐďƵůůĞƚŝƐŐƌĞĂƚĞƌƚŚĂŶD^^

ϭ͘ϭ dŚĞƌĞƋƵŝƌĞĚƌĞƉŽƌƚŝŶŐĨŽƌŵŝƐZ&Žƌŵϭ͘
ϭ͘Ϯ͘ dŚŝƐƌĞƋƵŝƌĞŵĞŶƚ;ŝŶŝƚƐĞŶƚŝƌĞƚLJͿĚŽĞƐŶŽƚĂƉƉůLJǁŚĞŶƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ
ĞdžƉĞƌŝĞŶĐŝŶŐĂZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚŝƐĞdžƉĞƌŝĞŶĐŝŶŐĂŶŶĞƌŐLJ
ŵĞƌŐĞŶĐLJůĞƌƚ>ĞǀĞůϮŽƌ>ĞǀĞůϯ͘
ĂĐŬŐƌŽƵŶĚĂŶĚZĂƚŝŽŶĂůĞ
ZĞƋƵŝƌĞŵĞŶƚZϭƌĞĨůĞĐƚƐƚŚĞŽƉĞƌĂƚŝŶŐƉƌŝŶĐŝƉůĞƐĨŝƌƐƚĞƐƚĂďůŝƐŚĞĚďLJEZWŽůŝĐLJϭ͘/ƚƐ
ŽďũĞĐƚŝǀĞŝƐƚŽĂƐƐƵƌĞƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJďĂůĂŶĐĞƐƌĞƐŽƵƌĐĞƐĂŶĚĚĞŵĂŶĚĂŶĚƌĞƚƵƌŶƐŝƚƐ
ƌĞĂŽŶƚƌŽůƌƌŽƌ;ͿƚŽĚĞĨŝŶĞĚǀĂůƵĞƐ;ƐƵďũĞĐƚƚŽĂƉƉůŝĐĂďůĞůŝŵŝƚƐͿĨŽůůŽǁŝŶŐĂZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͘/ƚƌĞƋƵŝƌĞƐƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJƚŽƌĞĐŽǀĞƌĨƌŽŵĞǀĞŶƚƐƚŚĂƚ
ǁŽƵůĚďĞůĞƐƐƚŚĂŶŽƌĞƋƵĂůƚŽƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛ƐD^^͘/ƚĞƐƚĂďůŝƐŚĞƐĂĐĞŝůŝŶŐĨŽƌƚŚĞ
ĂŵŽƵŶƚŽĨŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĂŶĚƚŝŵĞĨƌĂŵĞƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJŵƵƐƚĚĞŵŽŶƐƚƌĂƚĞŝŶĂ
ĐŽŵƉůŝĂŶĐĞĞǀĂůƵĂƚŝŽŶ͘/ƚŝƐŝŶƚĞŶĚĞĚƚŽĞůŝŵŝŶĂƚĞƚŚĞĂŵďŝŐƵŝƚŝĞƐĂŶĚƋƵĞƐƚŝŽŶƐĂƐƐŽĐŝĂƚĞĚ
ǁŝƚŚƚŚĞĞdžŝƐƚŝŶŐƐƚĂŶĚĂƌĚ͘/ŶĂĚĚŝƚŝŽŶ͕ŝƚĂůůŽǁƐZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ;ƐͿƚŽŚĂǀĞĂĐůĞĂƌǁĂLJƚŽ
ĚĞŵŽŶƐƚƌĂƚĞĐŽŵƉůŝĂŶĐĞĂŶĚƐƵƉƉŽƌƚƚŚĞ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶƚŽƚŚĞĨƵůůĞdžƚĞŶƚŽĨD^^͘
LJŝŶĐůƵĚŝŶŐŶĞǁĚĞĨŝŶŝƚŝŽŶƐ͕ĂŶĚŵŽĚŝĨLJŝŶŐĞdžŝƐƚŝŶŐĚĞĨŝŶŝƚŝŽŶƐ͕ĂŶĚƚŚĞĂďŽǀĞZϭ͕ƚŚĞĚƌĂĨƚŝŶŐ
ƚĞĂŵďĞůŝĞǀĞƐŝƚŚĂƐƐƵĐĐĞƐƐĨƵůůLJĨƵůĨŝůůĞĚƚŚĞƌĞƋƵŝƌĞŵĞŶƚƐŽĨ&ZKƌĚĞƌEŽ͘ϲϵϯ;ĂƚWϯϱϲͿƚŽ
ŝŶĐůƵĚĞĂZĞƋƵŝƌĞŵĞŶƚƚŚĂƚĞdžƉůŝĐŝƚůLJĂůůŽǁƐ^DƚŽďĞƵƐĞĚĂƐĂƌĞƐŽƵƌĐĞĨŽƌĐŽŶƚŝŶŐĞŶĐLJ
ZƌĞƐĞƌǀĞ͘/ƚĂůƐŽƌĞĐŽŐŶŝnjĞƐƚŚĂƚƚŚĞůŽƐƐŽĨƚƌĂŶƐŵŝƐƐŝŽŶĂƐǁĞůůĂƐŐĞŶĞƌĂƚŝŽŶŵĂLJƌĞƋƵŝƌĞƚŚĞ
ĚĞƉůŽLJŵĞŶƚŽĨĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞ͘
ĚĚŝƚŝŽŶĂůůLJ͕ZϭŝƐĚĞƐŝŐŶĞĚƚŽĂƐƐƵƌĞƚŚĞĂƉƉůŝĐĂďůĞĞŶƚŝƚLJŵƵƐƚƵƐĞƌĞƐĞƌǀĞƚŽĐŽǀĞƌĂ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚŽƌƚŚĞĐŽŵďŝŶĂƚŝŽŶŽĨĂŶLJƉƌĞǀŝŽƵƐĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐ
ƚŚĂƚŚĂǀĞŽĐĐƵƌƌĞĚǁŝƚŚŝŶƚŚĞƐƉĞĐŝĨŝĞĚƉĞƌŝŽĚ͕ƚŽĂĚĚƌĞƐƐƚŚĞKƌĚĞƌ͛ƐĐŽŶĐĞƌŶƚŚĂƚƚŚĞ
ĂƉƉůŝĐĂďůĞĞŶƚŝƚLJŝƐƌĞƐƉŽŶĚŝŶŐƚŽĞǀĞŶƚƐĂŶĚƉĞƌĨŽƌŵĂŶĐĞŝƐŵĞĂƐƵƌĞĚ͘dŚĞZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĚĞĨŝŶŝƚŝŽŶ͕ĂůŽŶŐǁŝƚŚZϭĂůůŽǁƐĨŽƌŵĞĂƐƵƌĞŵĞŶƚŽĨƉĞƌĨŽƌŵĂŶĐĞ͘
>ͲϬϬϮͲϮͲĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
:ƵůLJ͕ϮϬϭϯ

ϲ

ŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ&ƌŽŵĂĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ^ƚĂŶĚĂƌĚĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
dŚĞĚƌĂĨƚŝŶŐƚĞĂŵƵƐĞĚĚĂƚĂƐƵƉƉůŝĞĚďLJŽŶƐŽƌƚŝƵŵĨŽƌůĞĐƚƌŝĐZĞůŝĂďŝůŝƚLJdĞĐŚŶŽůŽŐLJ
^ŽůƵƚŝŽŶƐ;Zd^ͿƚŽŚĞůƉĚĞƚĞƌŵŝŶĞĂůůĞǀĞŶƚƐƚŚĂƚŚĂǀĞĂŶŝŵƉĂĐƚŽŶĨƌĞƋƵĞŶĐLJ͘ĂƚĂƚŚĂƚ
ǁĂƐĐŽŵƉŝůĞĚďLJZd^ƚŽƉƌŽǀŝĚĞŝŶĨŽƌŵĂƚŝŽŶŽŶŵĞĂƐƵƌĞĚĨƌĞƋƵĞŶĐLJĞǀĞŶƚƐŝƐƉƌĞƐĞŶƚĞĚŝŶ
ƚƚĂĐŚŵĞŶƚϭ͘ŶĂůLJnjŝŶŐƚŚĞĚĂƚĂ͕ŽŶĞĐŽƵůĚĚĞŵŽŶƐƚƌĂƚĞĞǀĞŶƚƐŽĨϭϬϬDtŽƌŐƌĞĂƚĞƌǁŽƵůĚ
ĐĂƉƚƵƌĞĂůůĨƌĞƋƵĞŶĐLJĞǀĞŶƚƐĨŽƌĂůůŝŶƚĞƌĐŽŶŶĞĐƚŝŽŶƐ͘,ŽǁĞǀĞƌ͕ĂƚĂϭϬϬDtƌĞƉŽƌƚŝŶŐ
ƚŚƌĞƐŚŽůĚ͕ƚŚĞŶƵŵďĞƌŽĨĞǀĞŶƚƐƌĞƉŽƌƚĞĚǁŽƵůĚƐŝŐŶŝĨŝĐĂŶƚůLJŝŶĐƌĞĂƐĞǁŝƚŚŶŽƌĞůŝĂďŝůŝƚLJŐĂŝŶ
ƐŝŶĐĞϭϬϬDtŝƐŵŽƌĞƌĞĨůĞĐƚŝǀĞŽĨƚŚĞŽƵƚůLJŝŶŐĞǀĞŶƚƐ͕ĞƐƉĞĐŝĂůůLJŽŶůĂƌŐĞƌŝŶƚĞƌĐŽŶŶĞĐƚŝŽŶƐ͘
dŚĞŐŽĂůŽĨƚŚĞĚƌĂĨƚŝŶŐƚĞĂŵǁĂƐƚŽĚĞƐŝŐŶĂĐŽŶƚŝŶĞŶƚͲǁŝĚĞƐƚĂŶĚĂƌĚƚŽĐĂƉƚƵƌĞƚŚĞŵĂũŽƌŝƚLJ
ŽĨƚŚĞĞǀĞŶƚƐƚŚĂƚŝŵƉĂĐƚĨƌĞƋƵĞŶĐLJ͘ĨƚĞƌƌZĞǀŝĞǁŝŶŐƚŚĞĚĂƚĂĂŶĚŝŶĚƵƐƚƌLJĐŽŵŵĞŶƚƐ͕ƚŚĞ
ĚƌĂĨƚŝŶŐƚĞĂŵĞůĞĐƚĞĚƚŽĞƐƚĂďůŝƐŚƌĞƉŽƌƚŝŶŐƚŚƌĞƐŚŽůĚŵŝŶŝŵƵŵƐĨŽƌĞĂĐŚƌĞƐƉĞĐƚŝǀĞ
/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͘ĐŽŶĐůƵĚĞĚ͕ďĂƐĞĚŽŶƚŚĞŵĞĚŝĂŶ͕ƚŽĞƐƚĂďůŝƐŚĂƐŝŶŐůĞĐŽŶƚŝŶĞŶƚͲǁŝĚĞƐƚĂŶĚĂƌĚ͘
dŚƵƐ͕ƐŽŵĞŝŶƚĞƌĐŽŶŶĞĐƚŝŽŶƐŵĂLJƌĞƉŽƌƚŵŽƌĞĞǀĞŶƚƐĂŶĚƐŽŵĞǁŽƵůĚƌĞƉŽƌƚůĞƐƐ͘dŚŝƐdŽ
ĂƐƐƵƌĞƐƚŚĞƌĞƋƵŝƌĞŵĞŶƚƐŽĨƚŚĞ&ZKƌĚĞƌEŽ͘ϲϵϯĂƌĞǁĞƌĞŵĞƚ͕͘ƚŚĞĚƌĂĨƚŝŶŐƚĞĂŵĚĞĐŝĚĞĚ
ƚŽĐĂƉƚƵƌĞƚŚĞŵĂũŽƌŝƚLJŽĨƚŚĞĞǀĞŶƚƐŚĂǀŝŶŐĂƐŝŐŶŝĨŝĐĂŶƚŝŵƉĂĐƚŽŶĨƌĞƋƵĞŶĐLJ͖dƚŚĞƌĞƉŽƌƚĂďůĞ
ƚŚƌĞƐŚŽůĚǁĂƐƐĞůĞĐƚĞĚĂƐƚŚĞůĞƐƐĞƌŽĨϴϬйŽĨƚŚĞĂƉƉůŝĐĂďůĞĞŶƚŝƚLJ;ƐͿDŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞ
ŽŶƚŝŶŐĞŶĐLJŽƌƚŚĞĨŽůůŽǁŝŶŐǀĂůƵĞƐĨŽƌĞĂĐŚƌĞƐƉĞĐƚŝǀĞ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͗ϱϬϬDt͘
•
•
•
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ĂƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶʹϵϬϬDt
tĞƐƚĞƌŶ/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶʹϱϬϬDt
ZKdʹϴϬϬDt
YƵĞďĞĐʹϱϬϬDt

ĚĚŝƚŝŽŶĂůůLJ͕ƚŚĞĚƌĂĨƚŝŶŐƚĞĂŵŽŶůLJƵƐĞĚƚŚĞƉŽƐŝƚŝǀĞĞǀĞŶƚƐĨŽƌƉƵƌƉŽƐĞƐŽĨĚĞƚĞƌŵŝŶŝŶŐƚŚĞ
ĂďŽǀĞƚŚƌĞƐŚŽůĚƐ͘
sŝŽůĂƚŝŽŶ^ĞǀĞƌŝƚLJ>ĞǀĞůƐ
/ŶƚŚĞsŝŽůĂƚŝŽŶ^ĞǀĞƌŝƚLJ>ĞǀĞůƐĨŽƌZĞƋƵŝƌĞŵĞŶƚZϭ͕ƚŚĞŝŵƉĂĐƚŽĨƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ
ƌĞĐŽǀĞƌŝŶŐĨƌŽŵĂZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĚĞƉĞŶĚƐŽŶƚŚĞĂŵŽƵŶƚŽĨŝƚƐ
ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĂǀĂŝůĂďůĞĂŶĚĚŽĞƐŝƚŚĂǀĞƐƵĨĨŝĐŝĞŶƚƌĞƐƉŽŶƐĞ͘dŚĞs^>ƚĂŬĞƐƚŚĞƐĞĨĂĐƚŽƌƐ
ŝŶƚŽĂĐĐŽƵŶƚ͘
ŽŵƉůŝĂŶĐĞĂůĐƵůĂƚŝŽŶ
dŽĚĞƚĞƌŵŝŶĞĐŽŵƉůŝĂŶĐĞǁŝƚŚZϭ͕ƚŚĞƌĞƋƵŝƌĞĚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞĂŶĚŵĞĂƐƵƌĞĚ
ĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞĂƌĞĐŽŵƉƵƚĞĚĂŶĚĐŽŵƉĂƌĞĚĂƐĨŽůůŽǁƐ;ĂƐƐƵŵŝŶŐĂůů
ƌĞƐŽƵƌĐĞůŽƐƐǀĂůƵĞƐ͕ŝ͘Ğ͘ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐ͕ĂƌĞƉŽƐŝƚŝǀĞͿ͗
ͻ dŚĞƌĞƋƵŝƌĞĚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞĞƋƵĂůƐƚŚĞůĞƐƐĞƌŽĨƚŚĞŵĞŐĂǁĂƚƚ
ůŽƐƐŽĨƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͕ĂŶĚ͕ƚŚĞDŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞ
ŽŶƚŝŶŐĞŶĐLJŵŝŶƵƐƚŚĞƐƵŵŽĨƚŚĞŵĞŐĂǁĂƚƚůŽƐƐĞƐŽĨĂŶLJƉƌĞǀŝŽƵƐĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐǁŚŽƐĞƐƚĂƌƚƉƌĞĐĞĚĞĚƚŚĞƐƚĂƌƚŽĨƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚďLJůĞƐƐƚŚĂŶƚŚĞƐƵŵŽĨƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ
ĂŶĚŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚ͘
ͻ dŚĞŵĞĂƐƵƌĞĚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞŝƐĞƋƵĂůƚŽŽŶĞŽĨƚŚĞĨŽůůŽǁŝŶŐ͗
>ͲϬϬϮͲϮͲĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
:ƵůLJ͕ϮϬϭϯ

ϳ

ŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ&ƌŽŵĂĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ^ƚĂŶĚĂƌĚĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
o /ĨƚŚĞWƌĞͲZĞƉŽƌƚĂďůĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞŝƐŐƌĞĂƚĞƌƚŚĂŶŽƌĞƋƵĂů
ƚŽnjĞƌŽ͕ƚŚĞŶƚŚĞŵĞĂƐƵƌĞĚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞĞƋƵĂůƐ;ĂͿƚŚĞ
ŵĞŐĂǁĂƚƚǀĂůƵĞŽĨƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƉůƵƐ;ďͿƚŚĞ
ŵŽƐƚƉŽƐŝƚŝǀĞǀĂůƵĞǁŝƚŚŝŶŝƚƐŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ;ĂŶĚ
ĨŽůůŽǁŝŶŐƚŚĞŽĐĐƵƌƌĞŶĐĞŽĨƚŚĞůĂƐƚƐƵďƐĞƋƵĞŶƚĞǀĞŶƚ͕ŝĨĂŶLJͿƉůƵƐ;ĐͿƚŚĞ
ƐƵŵŽĨƚŚĞŵĞŐĂǁĂƚƚůŽƐƐĞƐŽĨƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐ
ŽĐĐƵƌƌŝŶŐǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚŽĨƚŚĞZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͘
o /ĨƚŚĞWƌĞͲZĞƉŽƌƚĂďůĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞŝƐůĞƐƐƚŚĂŶnjĞƌŽ͕ƚŚĞŶƚŚĞ
ŵĞĂƐƵƌĞĚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞĞƋƵĂůƐ;ĂͿƚŚĞŵĞŐĂǁĂƚƚǀĂůƵĞŽĨ
ƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƉůƵƐ;ďͿƚŚĞŵŽƐƚƉŽƐŝƚŝǀĞ
ǀĂůƵĞǁŝƚŚŝŶŝƚƐŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ;ĂŶĚĨŽůůŽǁŝŶŐƚŚĞ
ŽĐĐƵƌƌĞŶĐĞŽĨƚŚĞůĂƐƚƐƵďƐĞƋƵĞŶƚĞǀĞŶƚ͕ŝĨĂŶLJͿƉůƵƐ;ĐͿƚŚĞƐƵŵŽĨƚŚĞ
ŵĞŐĂǁĂƚƚůŽƐƐĞƐŽĨƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐŽĐĐƵƌƌŝŶŐ
ǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚŽĨƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͕ŵŝŶƵƐ;ĚͿƚŚĞWƌĞͲZĞƉŽƌƚĂďůĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
sĂůƵĞ͘
ͻ ŽŵƉůŝĂŶĐĞŝƐĐŽŵƉƵƚĞĚĂƐĨŽůůŽǁƐŽŶZ&ŽƌŵϭŝŶŽƌĚĞƌƚŽĚŽĐƵŵĞŶƚĂůů
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƵƐĞĚŝŶĐŽŵƉůŝĂŶĐĞĚĞƚĞƌŵŝŶĂƚŝŽŶ͗
o /ĨƚŚĞƌĞƋƵŝƌĞĚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞŝƐůĞƐƐƚŚĂŶŽƌĞƋƵĂůƚŽnjĞƌŽ͕
ƚŚĞŶƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚŽŵƉůŝĂŶĐĞĞƋƵĂůƐϭϬϬ
ƉĞƌĐĞŶƚ͘
o /ĨƚŚĞƌĞƋƵŝƌĞĚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞŝƐŐƌĞĂƚĞƌƚŚĂŶnjĞƌŽ͕
ƒ

ĂŶĚŶĚƚŚĞŵĞĂƐƵƌĞĚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞŝƐŐƌĞĂƚĞƌƚŚĂŶ
ŽƌĞƋƵĂůƚŽƚŚĞƌĞƋƵŝƌĞĚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞ͕ƚŚĞŶƚŚĞ
ZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚŽŵƉůŝĂŶĐĞĞƋƵĂůƐϭϬϬ
ƉĞƌĐĞŶƚ͘

ƒ

ĂŶĚŶĚƚŚĞŵĞĂƐƵƌĞĚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞŝƐůĞƐƐƚŚĂŶŽƌ
ĞƋƵĂůƚŽnjĞƌŽ͕ƚŚĞŶƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
ŽŵƉůŝĂŶĐĞĞƋƵĂůƐϬƉĞƌĐĞŶƚ͘

ƒ

ĂŶĚŶĚƚŚĞŵĞĂƐƵƌĞĚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞŝƐůĞƐƐƚŚĂŶƚŚĞ
ƌĞƋƵŝƌĞĚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞďƵƚŐƌĞĂƚĞƌƚŚĂŶnjĞƌŽ͕ƚŚĞŶ
ƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚŽŵƉůŝĂŶĐĞĞƋƵĂůƐϭϬϬй
Ύ;ϭʹ;;ƌĞƋƵŝƌĞĚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞʹŵĞĂƐƵƌĞĚ
ĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞͿͬƌĞƋƵŝƌĞĚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞ
ƌĞƐƉŽŶƐĞͿͿ͘


dŚĞĂďŽǀĞĐŽŵƉƵƚĂƚŝŽŶƐĐĂŶďĞĞdžƉƌĞƐƐĞĚŵĂƚŚĞŵĂƚŝĐĂůůLJŝŶƚŚĞĨŽůůŽǁŝŶŐϳƐĞƋƵĞŶƚŝĂůƐƚĞƉƐ͕
ůĂďĞůĞĚĂƐ΀ϭͲϳ΁͕ǁŚĞƌĞ͗
>ͲϬϬϮͲϮͲĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
:ƵůLJ͕ϮϬϭϯ

ϴ

ŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ&ƌŽŵĂĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ^ƚĂŶĚĂƌĚĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
ͺ^dʹŵŽƐƚƉŽƐŝƚŝǀĞĚƵƌŝŶŐƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚŽĐĐƵƌƌŝŶŐĂĨƚĞƌ
ƚŚĞůĂƐƚƐƵďƐĞƋƵĞŶƚĞǀĞŶƚ͕ŝĨĂŶLJ;DtͿ
ͺWZͲWƌĞͲZĞƉŽƌƚĂďůĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞ;DtͿ
KDW>/EͲZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚŽŵƉůŝĂŶĐĞƉĞƌĐĞŶƚĂŐĞ;ϬͲϭϬϬйͿ
D^ͺZͺZ^WͲŵĞĂƐƵƌĞĚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞĨŽƌƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ;DtͿ
D^^ʹDŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;DtͿ
Dtͺ>K^dͲŵĞŐĂǁĂƚƚůŽƐƐŽĨƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ;DtͿ
ZYͺZͺZ^WʹƌĞƋƵŝƌĞĚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƐƉŽŶƐĞĨŽƌƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ;DtͿ
^hDͺWZsͲƐƵŵŽĨƚŚĞŵĞŐĂǁĂƚƚůŽƐƐĞƐŽĨĂŶLJƉƌĞǀŝŽƵƐĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐǁŚŽƐĞ
ƐƚĂƌƚƉƌĞĐĞĚĞƐƚŚĞƐƚĂƌƚŽĨƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚďLJůĞƐƐƚŚĂŶƚŚĞƐƵŵŽĨ
ƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚĂŶĚŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚ;DtͿ
^hDͺ^h^YͲƐƵŵŽĨƚŚĞŵĞŐĂǁĂƚƚůŽƐƐĞƐŽĨƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐ
ŽĐĐƵƌƌŝŶŐǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚŽĨƚŚĞZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ;DtͿ

ZYͺZͺZ^WсŵŝŶŝŵƵŵŽĨDtͺ>K^d͕ĂŶĚ͕;D^^ʹ^hDͺWZsͿ΀ϭ΁
/ĨͺWZŝƐŐƌĞĂƚĞƌƚŚĂŶŽƌĞƋƵĂůƚŽϬ͕ƚŚĞŶ
D^ͺZͺZ^WсDtͺ>K^dнͺ^dн^hDͺ^h^Y΀Ϯ΁

/ĨͺWZŝƐůĞƐƐƚŚĂŶϬ͕ƚŚĞŶ
D^ͺZͺZ^WсDtͺ>K^dнͺ^dн^hDͺ^h^YʹͺWZ΀ϯ΁

/ĨZYͺZͺZ^WŝƐůĞƐƐƚŚĂŶŽƌĞƋƵĂůƚŽϬ͕ƚŚĞŶKDW>/EсϭϬϬ΀ϰ΁

/ĨZYͺZͺZ^WŝƐŐƌĞĂƚĞƌƚŚĂŶϬ͕ĂŶĚ͕
D^ͺZͺZ^WŝƐŐƌĞĂƚĞƌƚŚĂŶŽƌĞƋƵĂůƚŽZYͺZͺZ^W͕ƚŚĞŶ
KDW>/EсϭϬϬ΀ϱ΁

/ĨZYͺZͺZ^WŝƐŐƌĞĂƚĞƌƚŚĂŶϬ͕ĂŶĚ͕D^ͺZͺZ^WŝƐůĞƐƐƚŚĂŶŽƌĞƋƵĂůƚŽϬ͕ƚŚĞŶ
KDW>/EсϬ΀ϲ΁
>ͲϬϬϮͲϮͲĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
:ƵůLJ͕ϮϬϭϯ

ϵ

ŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ&ƌŽŵĂĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ^ƚĂŶĚĂƌĚĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ

/ĨZYͺZͺZ^WŝƐŐƌĞĂƚĞƌƚŚĂŶϬ͕ĂŶĚ͕D^ͺZͺZ^WŝƐŐƌĞĂƚĞƌƚŚĂŶϬ͕ĂŶĚ͕
D^ͺZͺZ^WŝƐůĞƐƐƚŚĂŶZYͺZͺZ^W͕ƚŚĞŶ
KDW>/EсϭϬϬΎ;ϭʹ;;ZYͺZͺZ^WʹD^ͺZͺZ^WͿͬZYͺZͺZ^WͿͿ΀ϳ΁


ZĞƋƵŝƌĞŵĞŶƚϮ
ZϮ͘džĐĞƉƚĚƵƌŝŶŐƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛ƐŽŶƚŝŶŐĞŶĐLJǀĞŶƚŝƐƚƵƌďĂŶĐĞZĞĐŽǀĞƌLJWĞƌŝŽĚ
ĂŶĚƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛ƐŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞZĞƐƚŽƌĂƚŝŽŶZĞĐŽǀĞƌLJWĞƌŝŽĚ͕Žƌ
ĚƵƌŝŶŐĂŶŶĞƌŐLJŵĞƌŐĞŶĐLJůĞƌƚ>ĞǀĞůϮŽƌϯĨŽƌƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJĂŶĚĨŽƌĂŶ
ĂĚĚŝƚŝŽŶĂůĨŝǀĞŚŽƵƌƐĚƵƌŝŶŐĂŐŝǀĞŶĐĂůĞŶĚĂƌƋƵĂƌƚĞƌ͕ƚŚĞĞĂĐŚZĞƐƉŽŶƐŝďůĞŶƚŝƚLJƐŚĂůů
ŵĂŝŶƚĂŝŶĂŶĂŵŽƵŶƚŽĨŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĂƚůĞĂƐƚĞƋƵĂůƚŽŝƚƐDŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞ
ŽŶƚŝŶŐĞŶĐLJ͘
ĂĐŬŐƌŽƵŶĚĂŶĚZĂƚŝŽŶĂůĞ
ZϮĞƐƚĂďůŝƐŚĞƐĂƵŶŝĨŽƌŵĐŽŶƚŝŶĞŶƚͲǁŝĚĞĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƋƵŝƌĞŵĞŶƚ͘ZϮĞƐƚĂďůŝƐŚĞƐĂ
ƌĞƋƵŝƌĞŵĞŶƚƚŚĂƚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞďĞĂƚůĞĂƐƚĞƋƵĂůƚŽŝƚƐDŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ͘
LJŝŶĐůƵĚŝŶŐĂĚĞĨŝŶŝƚŝŽŶŽĨDŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJĂŶĚZϮ͕ĂĐŽŶƐŝƐƚĞŶƚƵŶŝĨŽƌŵ
ĐŽŶƚŝŶĞŶƚͲǁŝĚĞĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƌĞƋƵŝƌĞŵĞŶƚŚĂƐďĞĞŶĞƐƚĂďůŝƐŚĞĚ͘/ƚƐŐŽĂůŝƐƚŽĂƐƐƵƌĞ
ƚŚĂƚƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJǁŝůůŚĂǀĞƐƵĨĨŝĐŝĞŶƚĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƚŚĂƚĐĂŶďĞĚĞƉůŽLJĞĚƚŽ
ŵĞĞƚZϭ͘
&ZKƌĚĞƌϲϵϯ;ĂƚWϯϱϲͿĚŝƌĞĐƚĞĚ>ͲϬϬϮďĞĚĞǀĞůŽƉĞĚĂƐĂĐŽŶƚŝŶĞŶƚͲǁŝĚĞĐŽŶƚŝŶŐĞŶĐLJ
ƌĞƐĞƌǀĞƉŽůŝĐLJ͘ZϮĨƵůĨŝůůƐƚŚĞƌĞƋƵŝƌĞŵĞŶƚĂƐƐŽĐŝĂƚĞĚǁŝƚŚƚŚĞƌĞƋƵŝƌĞĚĂŵŽƵŶƚŽĨĐŽŶƚŝŶŐĞŶĐLJ
ƌĞƐĞƌǀĞĂZĞƐƉŽŶƐŝďůĞŶƚŝƚLJŵƵƐƚŚĂǀĞĂǀĂŝůĂďůĞƚŽƌĞƐƉŽŶĚƚŽĂZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͘tŝƚŚŝŶ&ZKƌĚĞƌϲϵϯ;ĂƚWϯϯϲͿƚŚĞŽŵŵŝƐƐŝŽŶŶŽƚĞĚƚŚĂƚƚŚĞ
ĂƉƉƌŽƉƌŝĂƚĞŵŝdžŽĨŽƉĞƌĂƚŝŶŐƌĞƐĞƌǀĞ͕ƐƉŝŶŶŝŶŐƌĞƐĞƌǀĞĂŶĚŶŽŶͲƐƉŝŶŶŝŶŐƌĞƐĞƌǀĞƐŚŽƵůĚďĞ
ĂĚĚƌĞƐƐĞĚ͘,ŽǁĞǀĞƌ͕ƚŚĞKƌĚĞƌƉƌĞĚĂƚĞĚƚŚĞĂƉƉƌŽǀĂůŽĨƚŚĞŶĞǁ>ͲϬϬϯ͕ǁŚŝĐŚĂĚĚƌĞƐƐĞƐ
ĨƌĞƋƵĞŶĐLJƌĞƐƉŽŶƐŝǀĞƌĞƐĞƌǀĞĂŶĚƚŚĞĂŵŽƵŶƚŽĨĨƌĞƋƵĞŶĐLJƌĞƐƉŽŶƐĞŽďůŝŐĂƚŝŽŶ͘tŝƚŚƚŚĞ
ĚĞǀĞůŽƉŵĞŶƚŽĨ>ͲϬϬϯ͕ĂŶĚƚŚĞĂƐƐŽĐŝĂƚĞĚƌĞůŝĂďŝůŝƚLJƉĞƌĨŽƌŵĂŶĐĞƌĞƋƵŝƌĞŵĞŶƚ͕ƚŚĞĚƌĂĨƚŝŶŐ
ƚĞĂŵďĞůŝĞǀĞƐƚŚĂƚ͕ǁŝƚŚZϮŽĨ>ͲϬϬϮĂŶĚƚŚĞĂƉƉƌŽǀĂůŽĨ>ͲϬϬϯ͕ƚŚĞŽŵŵŝƐƐŝŽŶ͛ƐŐŽĂůƐŽĨ
ĂĐŽŶƚŝŶĞŶƚͲǁŝĚĞĐŽŶƚŝŶŐĞŶĐLJƌĞƐĞƌǀĞƐƉŽůŝĐLJŝƐŵĞƚ͘dŚĞƐƵŝƚĞƐŽĨ>ƐƚĂŶĚĂƌĚƐ;>ͲϬϬϭ͕
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ƌĞƋƵŝƌĞŵĞŶƚƐǁŝƚŚŝŶĞĂĐŚƌĞƐƉĞĐƚŝǀĞƐƚĂŶĚĂƌĚ͕ĂĐŽŶƚŝŶĞŶƚͲǁŝĚĞĐŽŶƚŝŶŐĞŶĐLJƉŽůŝĐLJŝƐ
ĞƐƚĂďůŝƐŚĞĚ͘
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ƌĞĐŽǀĞƌŝŶŐĨƌŽŵĂZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĚĞƉĞŶĚƐŽŶƚŚĞĂŵŽƵŶƚŽĨŝƚƐ
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ƚĞĂŵƵŶĚĞƌƐƚĂŶĚƐƚŚĂƚZĞƐƉŽŶƐŝďůĞŶƚŝƚŝĞƐĂǀĂŝůĂďůĞŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞŵĂLJǀĂƌLJƐůŝŐŚƚůLJ
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ĐĂůĞŶĚĂƌƋƵĂƌƚĞƌ͕ƚŚĞĚƌĂĨƚŝŶŐŵŽĚŝĨŝĞĚƚŚĞƌĞƋƵŝƌĞŵĞŶƚƚŽƌĞĨůĞĐƚƐƵĐŚĂŶĞdžĞŵƉƚŝŽŶ͘LJ
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:ƵůLJ͕ϮϬϭϯ

ϭϬ

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ŝŶĐůƵĚŝŶŐƚŚĞĞdžĞŵƉƚŝŽŶƉƌŽǀŝĚĞƐƚŚĞŶĞĐĞƐƐĂƌLJĐŽŶƚŝŶƵŝƚLJďĞƚǁĞĞŶƚŚĞƌĞƋƵŝƌĞŵĞŶƚĂŶĚƚŚĞ
s^>͘dŚĞs^>ƚĂŬĞƐƚŚĞƐĞĨĂĐƚŽƌƐŝŶƚŽĂĐĐŽƵŶƚ͘


>ͲϬϬϮͲϮͲĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
:ƵůLJ͕ϮϬϭϯ



ϭϭ

ŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵ
ŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJ&ƌŽŵ
ŵĂĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶ
ŶĐLJǀĞŶƚ^ƚĂŶĚĂƌĚĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ

Attachment 1
NERC IInterconnections 2009
9-2012
Frequency
y Events Loss MW Sta
atistics

m
For: NERC BARC Standard Drafting Team
Prepared by: CERTS
Date: November 2, 2012


>ͲϬϬϮͲϮͲĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
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ϭϮ

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>ͲϬϬϮͲϮͲĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
:ƵůLJ͕ϮϬϭϯ

ϭϯ

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ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ^ƚĂŶĚĂƌĚĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ

>ͲϬϬϮͲϮͲĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
:ƵůLJ͕ϮϬϭϯ

ϭϰ

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ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ^ƚĂŶĚĂƌĚĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ

>ͲϬϬϮͲϮͲĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
:ƵůLJ͕ϮϬϭϯ

ϭϱ

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>ͲϬϬϮͲϮͲĂĐŬŐƌŽƵŶĚŽĐƵŵĞŶƚ
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ĞdžƉĞĐƚĞĚƚŽĂĚǀĞƌƐĞůLJĂĨĨĞĐƚƚŚĞĞůĞĐƚƌŝĐĂůƐƚĂƚĞŽƌĐĂƉĂďŝůŝƚLJŽĨƚŚĞƵůŬůĞĐƚƌŝĐ^LJƐƚĞŵ͕ŽƌƚŚĞĂďŝůŝƚLJƚŽ
ĞĨĨĞĐƚŝǀĞůLJŵŽŶŝƚŽƌĂŶĚĐŽŶƚƌŽůƚŚĞƵůŬůĞĐƚƌŝĐ^LJƐƚĞŵ͖ŽƌĂƌĞƋƵŝƌĞŵĞŶƚƚŚĂƚŝƐĂĚŵŝŶŝƐƚƌĂƚŝǀĞŝŶ
ŶĂƚƵƌĞĂŶĚĂƌĞƋƵŝƌĞŵĞŶƚŝŶĂƉůĂŶŶŝŶŐƚŝŵĞĨƌĂŵĞƚŚĂƚ͕ŝĨǀŝŽůĂƚĞĚ͕ǁŽƵůĚŶŽƚ͕ƵŶĚĞƌƚŚĞĞŵĞƌŐĞŶĐLJ͕
ĂďŶŽƌŵĂů͕ŽƌƌĞƐƚŽƌĂƚŝǀĞĐŽŶĚŝƚŝŽŶƐĂŶƚŝĐŝƉĂƚĞĚďLJƚŚĞƉƌĞƉĂƌĂƚŝŽŶƐ͕ďĞĞdžƉĞĐƚĞĚƚŽĂĚǀĞƌƐĞůLJĂĨĨĞĐƚƚŚĞ
ĞůĞĐƚƌŝĐĂůƐƚĂƚĞŽƌĐĂƉĂďŝůŝƚLJŽĨƚŚĞƵůŬůĞĐƚƌŝĐ^LJƐƚĞŵ͕ŽƌƚŚĞĂďŝůŝƚLJƚŽĞĨĨĞĐƚŝǀĞůLJŵŽŶŝƚŽƌ͕ĐŽŶƚƌŽů͕Žƌ
ƌĞƐƚŽƌĞƚŚĞƵůŬůĞĐƚƌŝĐ^LJƐƚĞŵ͘ƉůĂŶŶŝŶŐƌĞƋƵŝƌĞŵĞŶƚƚŚĂƚŝƐĂĚŵŝŶŝƐƚƌĂƚŝǀĞŝŶŶĂƚƵƌĞ͘
dŚĞ^dĂůƐŽĐŽŶƐŝĚĞƌĞĚĐŽŶƐŝƐƚĞŶĐLJǁŝƚŚƚŚĞ&ZsŝŽůĂƚŝŽŶZŝƐŬ&ĂĐƚŽƌ'ƵŝĚĞůŝŶĞƐĨŽƌƐĞƚƚŝŶŐsZ&Ɛ͗ϭ
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dŚĞĐŽŵŵŝƐƐŝŽŶƐĞĞŬƐƚŽĞŶƐƵƌĞƚŚĂƚsŝŽůĂƚŝŽŶZŝƐŬ&ĂĐƚŽƌƐĂƐƐŝŐŶĞĚƚŽƌĞƋƵŝƌĞŵĞŶƚƐŽĨƌĞůŝĂďŝůŝƚLJ
ƐƚĂŶĚĂƌĚƐŝŶƚŚĞƐĞŝĚĞŶƚŝĨŝĞĚĂƌĞĂƐĂƉƉƌŽƉƌŝĂƚĞůLJƌĞĨůĞĐƚƚŚĞŝƌŚŝƐƚŽƌŝĐĂůĐƌŝƚŝĐĂůŝŵƉĂĐƚŽŶƚŚĞƌĞůŝĂďŝůŝƚLJ
ŽĨƚŚĞƵůŬWŽǁĞƌ^LJƐƚĞŵ͘

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ƐĞǀĞƌĞůLJĂĨĨĞĐƚƚŚĞƌĞůŝĂďŝůŝƚLJŽĨƚŚĞƵůŬWŽǁĞƌ^LJƐƚĞŵ͗Ϯ

• ŵĞƌŐĞŶĐLJŽƉĞƌĂƚŝŽŶƐ
• sĞŐĞƚĂƚŝŽŶŵĂŶĂŐĞŵĞŶƚ
• KƉĞƌĂƚŽƌƉĞƌƐŽŶŶĞůƚƌĂŝŶŝŶŐ
• WƌŽƚĞĐƚŝŽŶƐLJƐƚĞŵƐĂŶĚƚŚĞŝƌĐŽŽƌĚŝŶĂƚŝŽŶ
• KƉĞƌĂƚŝŶŐƚŽŽůƐĂŶĚďĂĐŬƵƉĨĂĐŝůŝƚŝĞƐ
• ZĞĂĐƚŝǀĞƉŽǁĞƌĂŶĚǀŽůƚĂŐĞĐŽŶƚƌŽů
• ^LJƐƚĞŵŵŽĚĞůŝŶŐĂŶĚĚĂƚĂĞdžĐŚĂŶŐĞ
• ŽŵŵƵŶŝĐĂƚŝŽŶƉƌŽƚŽĐŽůĂŶĚĨĂĐŝůŝƚŝĞƐ
• ZĞƋƵŝƌĞŵĞŶƚƐƚŽĚĞƚĞƌŵŝŶĞĞƋƵŝƉŵĞŶƚƌĂƚŝŶŐƐ
• ^LJŶĐŚƌŽŶŝnjĞĚĚĂƚĂƌĞĐŽƌĚĞƌƐ
• ůĞĂƌĞƌĐƌŝƚĞƌŝĂĨŽƌŽƉĞƌĂƚŝŽŶĂůůLJĐƌŝƚŝĐĂůĨĂĐŝůŝƚŝĞƐ
• ƉƉƌŽƉƌŝĂƚĞƵƐĞŽĨƚƌĂŶƐŵŝƐƐŝŽŶůŽĂĚŝŶŐƌĞůŝĞĨ
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dŚĞĐŽŵŵŝƐƐŝŽŶĞdžƉĞĐƚƐĂƌĂƚŝŽŶĂůĐŽŶŶĞĐƚŝŽŶďĞƚǁĞĞŶƚŚĞƐƵďͲƌĞƋƵŝƌĞŵĞŶƚsŝŽůĂƚŝŽŶZŝƐŬ&ĂĐƚŽƌ
ĂƐƐŝŐŶŵĞŶƚƐĂŶĚƚŚĞŵĂŝŶƌĞƋƵŝƌĞŵĞŶƚsŝŽůĂƚŝŽŶZŝƐŬ&ĂĐƚŽƌĂƐƐŝŐŶŵĞŶƚ͘
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EŽƌƚŚŵĞƌŝĐĂŶůĞĐƚƌŝĐZĞůŝĂďŝůŝƚLJŽƌƉ͕͘ϭϭϵ&ZΒϲϭ͕ϭϰϱ͕ŽƌĚĞƌŽŶƌĞŚ͛ŐĂŶĚĐŽŵƉůŝĂŶĐĞĨŝůŝŶŐ͕ϭϮϬ&ZΒϲϭ͕ϭϰϱ
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dŚĞĐŽŵŵŝƐƐŝŽŶĞdžƉĞĐƚƐƚŚĞĂƐƐŝŐŶŵĞŶƚŽĨsŝŽůĂƚŝŽŶZŝƐŬ&ĂĐƚŽƌƐĐŽƌƌĞƐƉŽŶĚŝŶŐƚŽƌĞƋƵŝƌĞŵĞŶƚƐƚŚĂƚ
ĂĚĚƌĞƐƐƐŝŵŝůĂƌƌĞůŝĂďŝůŝƚLJŐŽĂůƐŝŶĚŝĨĨĞƌĞŶƚƌĞůŝĂďŝůŝƚLJƐƚĂŶĚĂƌĚƐǁŽƵůĚďĞƚƌĞĂƚĞĚĐŽŵƉĂƌĂďůLJ͘
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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.
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ŽďũĞĐƚŝǀĞ͕ƚŚĞsZ&ĂƐƐŝŐŶŵĞŶƚĨŽƌƐƵĐŚƌĞƋƵŝƌĞŵĞŶƚŵƵƐƚŶŽƚďĞǁĂƚĞƌĞĚĚŽǁŶƚŽƌĞĨůĞĐƚƚŚĞůŽǁĞƌƌŝƐŬ
ůĞǀĞůĂƐƐŽĐŝĂƚĞĚǁŝƚŚƚŚĞůĞƐƐŝŵƉŽƌƚĂŶƚŽďũĞĐƚŝǀĞŽĨƚŚĞƌĞůŝĂďŝůŝƚLJƐƚĂŶĚĂƌĚ͘

dŚĞĨŽůůŽǁŝŶŐĚŝƐĐƵƐƐŝŽŶĂĚĚƌĞƐƐĞƐŚŽǁƚŚĞ^dĐŽŶƐŝĚĞƌĞĚ&Z͛ƐsZ&'ƵŝĚĞůŝŶĞƐϮƚŚƌŽƵŐŚϱ͘dŚĞ
ƚĞĂŵĚŝĚŶŽƚĂĚĚƌĞƐƐ'ƵŝĚĞůŝŶĞϭĚŝƌĞĐƚůLJďĞĐĂƵƐĞŽĨĂŶĂƉƉĂƌĞŶƚĐŽŶĨůŝĐƚďĞƚǁĞĞŶ'ƵŝĚĞůŝŶĞƐϭĂŶĚϰ͘
tŚĞƌĞĂƐ'ƵŝĚĞůŝŶĞϭŝĚĞŶƚŝĨŝĞƐĂůŝƐƚŽĨƚŽƉŝĐƐƚŚĂƚĞŶĐŽŵƉĂƐƐŶĞĂƌůLJĂůůƚŽƉŝĐƐǁŝƚŚŝŶEZ͛ƐƌĞůŝĂďŝůŝƚLJ
ƐƚĂŶĚĂƌĚƐĂŶĚŝŵƉůŝĞƐƚŚĂƚƚŚĞƐĞƌĞƋƵŝƌĞŵĞŶƚƐƐŚŽƵůĚďĞĂƐƐŝŐŶĞĚĂ͞,ŝŐŚ͟sZ&͕'ƵŝĚĞůŝŶĞϰĚŝƌĞĐƚƐ
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ĐŽŶĐĞŶƚƌĂƚĞĚŝƚƐĂƉƉƌŽĂĐŚŽŶƚŚĞƌĞůŝĂďŝůŝƚLJŝŵƉĂĐƚŽĨƚŚĞƌĞƋƵŝƌĞŵĞŶƚƐ͘

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ĐŽŶƚĂŝŶƐƵďͲƌĞƋƵŝƌĞŵĞŶƚƐ͘ŽƚŚƌĞƋƵŝƌĞŵĞŶƚƐŝŶ>ͲϬϬϮͲϮĂƌĞĂƐƐŝŐŶĞĚĂ͞DĞĚŝƵŵ͟sZ&͘
ZĞƋƵŝƌĞŵĞŶƚZϭŝƐƐŝŵŝůĂƌŝŶƐĐŽƉĞƚŽZĞƋƵŝƌĞŵĞŶƚZϮ͘dŚŝƐŝƐĂůƐŽĐŽŶƐŝƐƚĞŶƚǁŝƚŚŽƚŚĞƌ
ƌĞůŝĂďŝůŝƚLJƐƚĂŶĚĂƌĚƐ;ŝ͘Ğ͕͘>ͲϬϬϭͲϮ͕>ͲϬϬϯͲϭ͕ĞƚĐͿ͘

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ƌĞƋƵŝƌĞŵĞŶƚ͕ŝĨǀŝŽůĂƚĞĚ͕ĐŽƵůĚĚŝƌĞĐƚůLJĂĨĨĞĐƚƚŚĞĞůĞĐƚƌŝĐĂůƐƚĂƚĞŽƌƚŚĞĐĂƉĂďŝůŝƚLJŽĨƚŚĞƵůŬ
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ĐĂƐĐĂĚŝŶŐĨĂŝůƵƌĞƐƐŝŶĐĞƚŚŝƐƌĞƋƵŝƌĞŵĞŶƚŝƐĂŶĂĨƚĞƌͲƚŚĞͲĨĂĐƚĐĂůĐƵůĂƚŝŽŶ͕ŶŽƚƉĞƌĨŽƌŵĞĚŝŶZĞĂůͲ
ƚŝŵĞ͘

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ĐŽŶƚĂŝŶƐƵďƌĞƋƵŝƌĞŵĞŶƚƐ͘ŽƚŚƌĞƋƵŝƌĞŵĞŶƚƐŝŶ>ͲϬϬϮͲϮĂƌĞĂƐƐŝŐŶĞĚĂ͞DĞĚŝƵŵ͟sZ&͘
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ƌĞůŝĂďŝůŝƚLJƐƚĂŶĚĂƌĚƐ;ŝ͘Ğ͕͘>ͲϬϬϭͲϮ͕>ͲϬϬϯͲϭ͕ĞƚĐͿ͘

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&Z'ƵŝĚĞůŝŶĞϯͶŽŶƐŝƐƚĞŶĐLJĂŵŽŶŐZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚƐĞdžŝƐƚƐ͘dŚŝƐƌĞƋƵŝƌĞŵĞŶƚŝƐƐŝŵŝůĂƌ
ŝŶĐŽŶĐĞƉƚƚŽƚŚĞĐƵƌƌĞŶƚĞŶĨŽƌĐĞĂďůĞ>ͲϬϬϭͲϬ͘ϭĂƐƚĂŶĚĂƌĚZĞƋƵŝƌĞŵĞŶƚƐZϭĂŶĚZϮ͕ǁŚŝĐŚ
ŚĂǀĞĂŶĂƉƉƌŽǀĞĚDĞĚŝƵŵsZ&͕ƉƌŽƉŽƐĞĚ>ͲϬϬϭͲϭĂŶĚ>ͲϬϬϯͲϭ͘

ͻ

&Z'ƵŝĚĞůŝŶĞϰͶŽŶƐŝƐƚĞŶĐLJǁŝƚŚEZ͛ƐĞĨŝŶŝƚŝŽŶŽĨƚŚĞsZ&ůĞǀĞůƐĞůĞĐƚĞĚĞdžŝƐƚƐ͘dŚŝƐ
ƌĞƋƵŝƌĞŵĞŶƚ͕ŝĨǀŝŽůĂƚĞĚ͕ĐŽƵůĚĚŝƌĞĐƚůLJĂĨĨĞĐƚƚŚĞĞůĞĐƚƌŝĐĂůƐƚĂƚĞŽƌƚŚĞĐĂƉĂďŝůŝƚLJŽĨƚŚĞƵůŬ
ůĞĐƚƌŝĐ^LJƐƚĞŵ͕ŽƌƚŚĞĂďŝůŝƚLJƚŽĞĨĨĞĐƚŝǀĞůLJŵŽŶŝƚŽƌĂŶĚĐŽŶƚƌŽůƚŚĞƵůŬůĞĐƚƌŝĐ^LJƐƚĞŵ͕ďƵƚ
ǀŝŽůĂƚŝŽŶ͕ŝŶŝƚƐĞůĨ͕ǁŽƵůĚƵŶůŝŬĞůLJƌĞƐƵůƚŝŶƚŚĞƵůŬůĞĐƚƌŝĐ^LJƐƚĞŵŝŶƐƚĂďŝůŝƚLJ͕ƐĞƉĂƌĂƚŝŽŶ͕Žƌ
ĐĂƐĐĂĚŝŶŐĨĂŝůƵƌĞƐƐŝŶĐĞƚŚŝƐƌĞƋƵŝƌĞŵĞŶƚŝƐĂŶĂĨƚĞƌͲƚŚĞͲĨĂĐƚĐĂůĐƵůĂƚŝŽŶ͕ŶŽƚƉĞƌĨŽƌŵĞĚŝŶZĞĂůͲ
ƚŝŵĞ͘

ͻ

&Z'ƵŝĚĞůŝŶĞϱͶdŚŝƐƌĞƋƵŝƌĞŵĞŶƚĚŽĞƐŶŽƚĐŽͲŵŝŶŐůĞƌĞůŝĂďŝůŝƚLJŽďũĞĐƚŝǀĞƐ͘





>ͲϬϬϮͲϮ
sZ&ĂŶĚs^>ƐƐŝŐŶŵĞŶƚƐʹ:ƵůLJ͕ϮϬϭϯ



ϰ

-XVWLILFDWLRQIRU$VVLJQPHQWRI9LRODWLRQ6HYHULW\/HYHOV

/ŶĚĞǀĞůŽƉŝŶŐƚŚĞs^>ƐĨŽƌƚŚĞƐƚĂŶĚĂƌĚƐƵŶĚĞƌƚŚŝƐƉƌŽũĞĐƚ͕ƚŚĞ^dĂŶƚŝĐŝƉĂƚĞĚƚŚĞĞǀŝĚĞŶĐĞƚŚĂƚǁŽƵůĚ
ďĞƌĞǀŝĞǁĞĚĚƵƌŝŶŐĂŶĂƵĚŝƚ͕ĂŶĚĚĞǀĞůŽƉĞĚŝƚƐs^>ƐďĂƐĞĚŽŶƚŚĞŶŽŶĐŽŵƉůŝĂŶĐĞĂŶĂƵĚŝƚŽƌŵĂLJĨŝŶĚ
ĚƵƌŝŶŐĂƚLJƉŝĐĂůĂƵĚŝƚ͘dŚĞ^dďĂƐĞĚŝƚƐĂƐƐŝŐŶŵĞŶƚŽĨs^>ƐŽŶƚŚĞĨŽůůŽǁŝŶŐEZĐƌŝƚĞƌŝĂ͗
>ŽǁĞƌ

DŽĚĞƌĂƚĞ

DŝƐƐŝŶŐĂŵŝŶŽƌ
DŝƐƐŝŶŐĂƚůĞĂƐƚŽŶĞ
ĞůĞŵĞŶƚ;ŽƌĂƐŵĂůů
ƐŝŐŶŝĨŝĐĂŶƚĞůĞŵĞŶƚ;Žƌ
ƉĞƌĐĞŶƚĂŐĞͿŽĨƚŚĞ
ĂŵŽĚĞƌĂƚĞ
ƌĞƋƵŝƌĞĚƉĞƌĨŽƌŵĂŶĐĞ͘ ƉĞƌĐĞŶƚĂŐĞͿŽĨƚŚĞ
ƌĞƋƵŝƌĞĚƉĞƌĨŽƌŵĂŶĐĞ͘
dŚĞƉĞƌĨŽƌŵĂŶĐĞŽƌ
ƉƌŽĚƵĐƚŵĞĂƐƵƌĞĚŚĂƐ dŚĞƉĞƌĨŽƌŵĂŶĐĞŽƌ
ƐŝŐŶŝĨŝĐĂŶƚǀĂůƵĞ͕ĂƐŝƚ ƉƌŽĚƵĐƚŵĞĂƐƵƌĞĚƐƚŝůů
ĂůŵŽƐƚŵĞĞƚƐƚŚĞĨƵůů ŚĂƐƐŝŐŶŝĨŝĐĂŶƚǀĂůƵĞŝŶ
ŝŶƚĞŶƚŽĨƚŚĞ
ŵĞĞƚŝŶŐƚŚĞŝŶƚĞŶƚŽĨ
ƌĞƋƵŝƌĞŵĞŶƚ͘
ƚŚĞƌĞƋƵŝƌĞŵĞŶƚ͘

,ŝŐŚ

^ĞǀĞƌĞ

DŝƐƐŝŶŐŵŽƌĞƚŚĂŶŽŶĞ
ƐŝŐŶŝĨŝĐĂŶƚĞůĞŵĞŶƚ;Žƌ
ŝƐŵŝƐƐŝŶŐĂŚŝŐŚ
ƉĞƌĐĞŶƚĂŐĞͿŽĨƚŚĞ
ƌĞƋƵŝƌĞĚƉĞƌĨŽƌŵĂŶĐĞ͕
ŽƌŝƐŵŝƐƐŝŶŐĂƐŝŶŐůĞ
ǀŝƚĂůĐŽŵƉŽŶĞŶƚ͘
dŚĞƉĞƌĨŽƌŵĂŶĐĞŽƌ
ƉƌŽĚƵĐƚŚĂƐůŝŵŝƚĞĚ
ǀĂůƵĞŝŶŵĞĞƚŝŶŐƚŚĞ
ŝŶƚĞŶƚŽĨƚŚĞ
ƌĞƋƵŝƌĞŵĞŶƚ͘

DŝƐƐŝŶŐŵŽƐƚŽƌĂůůŽĨ
ƚŚĞƐŝŐŶŝĨŝĐĂŶƚ
ĞůĞŵĞŶƚƐ;ŽƌĂ
ƐŝŐŶŝĨŝĐĂŶƚƉĞƌĐĞŶƚĂŐĞͿ
ŽĨƚŚĞƌĞƋƵŝƌĞĚ
ƉĞƌĨŽƌŵĂŶĐĞ͘
dŚĞƉĞƌĨŽƌŵĂŶĐĞ
ŵĞĂƐƵƌĞĚĚŽĞƐŶŽƚ
ŵĞĞƚƚŚĞŝŶƚĞŶƚŽĨƚŚĞ
ƌĞƋƵŝƌĞŵĞŶƚ͕ŽƌƚŚĞ
ƉƌŽĚƵĐƚĚĞůŝǀĞƌĞĚ
ĐĂŶŶŽƚďĞƵƐĞĚŝŶ
ŵĞĞƚŝŶŐƚŚĞŝŶƚĞŶƚŽĨ
ƚŚĞƌĞƋƵŝƌĞŵĞŶƚ͘

&Z͛Ɛs^>'ƵŝĚĞůŝŶĞƐĂƌĞƉƌĞƐĞŶƚĞĚďĞůŽǁ͕ĨŽůůŽǁĞĚďLJĂŶĂŶĂůLJƐŝƐŽĨǁŚĞƚŚĞƌƚŚĞs^>ƐƉƌŽƉŽƐĞĚĨŽƌ
ĞĂĐŚƌĞƋƵŝƌĞŵĞŶƚŝŶ>ͲϬϬϮͲϮŵĞĞƚƚŚĞ&Z'ƵŝĚĞůŝŶĞƐĨŽƌĂƐƐĞƐƐŝŶŐs^>Ɛ͗



>ͲϬϬϮͲϮ
sZ&ĂŶĚs^>ƐƐŝŐŶŵĞŶƚƐʹ:ƵůLJ͕ϮϬϭϯ

ϱ

*XLGHOLQH9LRODWLRQ6HYHULW\/HYHO$VVLJQPHQWV6KRXOG1RW+DYHWKH8QLQWHQGHG
&RQVHTXHQFHRI/RZHULQJWKH&XUUHQW/HYHORI&RPSOLDQFH

ŽŵƉĂƌĞƚŚĞs^>ƐƚŽĂŶLJƉƌŝŽƌůĞǀĞůƐŽĨŶŽŶĐŽŵƉůŝĂŶĐĞĂŶĚĂǀŽŝĚƐŝŐŶŝĨŝĐĂŶƚĐŚĂŶŐĞƐƚŚĂƚŵĂLJ
ĞŶĐŽƵƌĂŐĞĂůŽǁĞƌůĞǀĞůŽĨĐŽŵƉůŝĂŶĐĞƚŚĂŶǁĂƐƌĞƋƵŝƌĞĚǁŚĞŶůĞǀĞůƐŽĨŶŽŶĐŽŵƉůŝĂŶĐĞǁĞƌĞƵƐĞĚ͘
*XLGHOLQH9LRODWLRQ6HYHULW\/HYHO$VVLJQPHQWV6KRXOG(QVXUH8QLIRUPLW\DQG
&RQVLVWHQF\LQWKH'HWHUPLQDWLRQRI3HQDOWLHV

ǀŝŽůĂƚŝŽŶŽĨĂ͞ďŝŶĂƌLJ͟ƚLJƉĞƌĞƋƵŝƌĞŵĞŶƚŵƵƐƚďĞĂ͞^ĞǀĞƌĞ͟s^>͘
ŽŶŽƚƵƐĞĂŵďŝŐƵŽƵƐƚĞƌŵƐƐƵĐŚĂƐ͞ŵŝŶŽƌ͟ĂŶĚ͞ƐŝŐŶŝĨŝĐĂŶƚ͟ƚŽĚĞƐĐƌŝďĞŶŽŶĐŽŵƉůŝĂŶƚƉĞƌĨŽƌŵĂŶĐĞ͘
*XLGHOLQH9LRODWLRQ6HYHULW\/HYHO$VVLJQPHQW6KRXOG%H&RQVLVWHQWZLWKWKH
&RUUHVSRQGLQJ5HTXLUHPHQW

s^>ƐƐŚŽƵůĚŶŽƚĞdžƉĂŶĚŽŶǁŚĂƚŝƐƌĞƋƵŝƌĞĚŝŶƚŚĞƌĞƋƵŝƌĞŵĞŶƚ͘
*XLGHOLQH9LRODWLRQ6HYHULW\/HYHO$VVLJQPHQW6KRXOG%H%DVHGRQ$6LQJOH9LRODWLRQ
1RWRQ$&XPXODWLYH1XPEHURI9LRODWLRQV

͘͘͘ƵŶůĞƐƐŽƚŚĞƌǁŝƐĞƐƚĂƚĞĚŝŶƚŚĞƌĞƋƵŝƌĞŵĞŶƚ͕ĞĂĐŚŝŶƐƚĂŶĐĞŽĨŶŽŶĐŽŵƉůŝĂŶĐĞǁŝƚŚĂƌĞƋƵŝƌĞŵĞŶƚŝƐĂ
ƐĞƉĂƌĂƚĞǀŝŽůĂƚŝŽŶ͘^ĞĐƚŝŽŶϰŽĨƚŚĞ^ĂŶĐƚŝŽŶ'ƵŝĚĞůŝŶĞƐƐƚĂƚĞƐƚŚĂƚĂƐƐĞƐƐŝŶŐƉĞŶĂůƚŝĞƐŽŶĂƉĞƌͲ
ǀŝŽůĂƚŝŽŶͲƉĞƌͲĚĂLJďĂƐŝƐŝƐƚŚĞ͞ĚĞĨĂƵůƚ͟ĨŽƌƉĞŶĂůƚLJĐĂůĐƵůĂƚŝŽŶƐ͘

>ͲϬϬϮͲϮ
sZ&ĂŶĚs^>ƐƐŝŐŶŵĞŶƚƐʹ:ƵůLJ͕ϮϬϭϯ

ϲ

dŚĞEZs^>
'ƵŝĚĞůŝŶĞƐĂƌĞ
ƐĂƚŝƐĨŝĞĚďLJ
ŝŶĐŽƌƉŽƌĂƚŝŶŐ
ƉĞƌĐĞŶƚĂŐĞŽĨ
ŶŽŶĐŽŵƉůŝĂŶĐĞ
ƉĞƌĨŽƌŵĂŶĐĞĨŽƌ
ƚŚĞĐĂůĐƵůĂƚĞĚ
W^ϭ͘

ƐĚƌĂĨƚĞĚ͕ƚŚĞ
ƉƌŽƉŽƐĞĚs^>ƐĚŽŶŽƚ
ůŽǁĞƌƚŚĞĐƵƌƌĞŶƚůĞǀĞů
ŽĨĐŽŵƉůŝĂŶĐĞ͘

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

WƌŽƉŽƐĞĚs^>ƐĂƌĞŶŽƚďŝŶĂƌLJ͘
WƌŽƉŽƐĞĚs^>ůĂŶŐƵĂŐĞĚŽĞƐŶŽƚ
ŝŶĐůƵĚĞĂŵďŝŐƵŽƵƐƚĞƌŵƐĂŶĚ
ĞŶƐƵƌĞƐƵŶŝĨŽƌŵŝƚLJĂŶĚ
ĐŽŶƐŝƐƚĞŶĐLJŝŶƚŚĞ
ĚĞƚĞƌŵŝŶĂƚŝŽŶŽĨƉĞŶĂůƚŝĞƐ
ďĂƐĞĚŽŶůLJŽŶƚŚĞƉĞƌĐĞŶƚĂŐĞŽĨ
ŝŶƚĞƌǀĂůƐƚŚĞĞŶƚŝƚLJŝƐ
ŶŽŶĐŽŵƉůŝĂŶƚ͘

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

>ͲϬϬϮͲϮ
sZ&ĂŶĚs^>ƐƐŝŐŶŵĞŶƚƐʹ:ƵůLJ͕ϮϬϭϯ

Zϭ

R#

Compliance with
NERC VSL
Guidelines

96/VIRU%$/5HTXLUHPHQW5


WƌŽƉŽƐĞĚs^>ƐĚŽŶŽƚ
ĞdžƉĂŶĚŽŶǁŚĂƚŝƐ
ƌĞƋƵŝƌĞĚŝŶƚŚĞ
ƌĞƋƵŝƌĞŵĞŶƚ͘dŚĞs^>Ɛ
ĂƐƐŝŐŶĞĚŽŶůLJĐŽŶƐŝĚĞƌ
ƌĞƐƵůƚƐŽĨƚŚĞĐĂůĐƵůĂƚŝŽŶ
ƌĞƋƵŝƌĞĚ͘WƌŽƉŽƐĞĚs^>Ɛ
ĂƌĞĐŽŶƐŝƐƚĞŶƚǁŝƚŚƚŚĞ
ƌĞƋƵŝƌĞŵĞŶƚ͘

Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement

Guideline 3



ϳ



WƌŽƉŽƐĞĚs^>ƐĂƌĞ
ďĂƐĞĚŽŶƐŝŶŐůĞ
ǀŝŽůĂƚŝŽŶƐĂŶĚŶŽƚĂ
ĐƵŵƵůĂƚŝǀĞǀŝŽůĂƚŝŽŶ
ŵĞƚŚŽĚŽůŽŐLJ͘

Violation Severity Level
Assignment Should Be
Based on A Single
Violation, Not on A
Cumulative Number of
Violations

Guideline 4

dŚĞEZs^>
'ƵŝĚĞůŝŶĞƐĂƌĞ
ƐĂƚŝƐĨŝĞĚďLJ
ŝŶĐŽƌƉŽƌĂƚŝŶŐ
ůĞǀĞůƐŽĨ
ŶŽŶĐŽŵƉůŝĂŶĐĞ
ƉĞƌĨŽƌŵĂŶĐĞ͘

dŚŝƐŝƐĂŶĞǁƌĞƋƵŝƌĞŵĞŶƚ͘
ƐĚƌĂĨƚĞĚ͕ƚŚĞƉƌŽƉŽƐĞĚ
s^>ƐĚŽŶŽƚůŽǁĞƌƚŚĞ
ĐƵƌƌĞŶƚůĞǀĞůŽĨĐŽŵƉůŝĂŶĐĞ͘

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

WƌŽƉŽƐĞĚs^>ƐĂƌĞŶŽƚ
ďŝŶĂƌLJ͘WƌŽƉŽƐĞĚs^>
ůĂŶŐƵĂŐĞĚŽĞƐŶŽƚŝŶĐůƵĚĞ
ĂŵďŝŐƵŽƵƐƚĞƌŵƐĂŶĚ
ĞŶƐƵƌĞƐƵŶŝĨŽƌŵŝƚLJĂŶĚ
ĐŽŶƐŝƐƚĞŶĐLJŝŶƚŚĞ
ĚĞƚĞƌŵŝŶĂƚŝŽŶŽĨƉĞŶĂůƚŝĞƐ
ďĂƐĞĚŽŶůLJŽŶƚŚĞĂŵŽƵŶƚŽĨ
ƚŝŵĞƚŚĞĞŶƚŝƚLJŝƐ
ŶŽŶĐŽŵƉůŝĂŶƚ͘

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

>ͲϬϬϮͲϮ
sZ&ĂŶĚs^>ƐƐŝŐŶŵĞŶƚƐʹ:ƵůLJ͕ϮϬϭϯ

ZϮ͘

R#

Compliance with
NERC VSL
Guidelines

96/VIRU%$/5HTXLUHPHQW5


WƌŽƉŽƐĞĚs^>ƐĚŽŶŽƚ
ĞdžƉĂŶĚŽŶǁŚĂƚŝƐ
ƌĞƋƵŝƌĞĚŝŶƚŚĞ
ƌĞƋƵŝƌĞŵĞŶƚ͘dŚĞs^>Ɛ
ĂƐƐŝŐŶĞĚŽŶůLJĐŽŶƐŝĚĞƌ
ƚŚĞĂŵŽƵŶƚŽĨƚŝŵĞĂŶ
ĞŶƚŝƚLJŝƐŶŽŶͲĐŽŵƉůŝĂŶƚ
ǁŝƚŚƚŚĞƌĞƋƵŝƌĞŵĞŶƚ͘
WƌŽƉŽƐĞĚs^>ƐĂƌĞ
ĐŽŶƐŝƐƚĞŶƚǁŝƚŚƚŚĞ
ƌĞƋƵŝƌĞŵĞŶƚ͘

Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement

Guideline 3



ϴ



WƌŽƉŽƐĞĚs^>ƐĂƌĞ
ďĂƐĞĚŽŶƐŝŶŐůĞ
ǀŝŽůĂƚŝŽŶƐĂŶĚŶŽƚĂ
ĐƵŵƵůĂƚŝǀĞ
ǀŝŽůĂƚŝŽŶ
ŵĞƚŚŽĚŽůŽŐLJ͘

Violation Severity
Level Assignment
Should Be Based on
A Single Violation,
Not on A Cumulative
Number of Violations

Guideline 4

>ͲϬϬϮͲϬDĂƉƉŝŶŐƚŽWƌŽƉŽƐĞĚEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ
^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϬ
ŽŵŵĞŶƚ
WƌŽƉŽƐĞĚ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ
EZŽĂƌĚƉƉƌŽǀĞĚ
Zϭ͘ ĂĐŚĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJƐŚĂůů
dŚŝƐZĞƋƵŝƌĞŵĞŶƚŚĂƐďĞĞŶ
ƉƉůŝĐĂďŝůŝƚLJ
ŚĂǀĞĂĐĐĞƐƐƚŽĂŶĚͬŽƌŽƉĞƌĂƚĞ
ŵŽǀĞĚŝŶƚŽ>ͲϬϬϮͲϮ
ϰ͘ϭ͘ ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ
ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞƚŽƌĞƐƉŽŶĚƚŽ
ƉƉůŝĐĂďŝůŝƚLJĂŶĚ͞ĚĚŝƚŝŽŶĂů
ŝƐƚƵƌďĂŶĐĞƐ͘ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞŵĂLJ ŽŵƉůŝĂŶĐĞ/ŶĨŽƌŵĂƚŝŽŶ͟
ϰ͘ϭ͘ϭ ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJƚŚĂƚŝƐĂŵĞŵďĞƌŽĨĂ
ďĞƐƵƉƉůŝĞĚĨƌŽŵŐĞŶĞƌĂƚŝŽŶ͕
ƐĞĐƚŝŽŶƐ
ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉŝƐƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ
ĐŽŶƚƌŽůůĂďůĞůŽĂĚƌĞƐŽƵƌĐĞƐ͕Žƌ
ŽŶůLJŝŶƉĞƌŝŽĚƐĚƵƌŝŶŐǁŚŝĐŚƚŚĞĂůĂŶĐŝŶŐ
ĐŽŽƌĚŝŶĂƚĞĚĂĚũƵƐƚŵĞŶƚƐƚŽ/ŶƚĞƌĐŚĂŶŐĞ
ƵƚŚŽƌŝƚLJŝƐŶŽƚŝŶĂĐƚŝǀĞƐƚĂƚƵƐƵŶĚĞƌƚŚĞ
^ĐŚĞĚƵůĞƐ͘
ĂƉƉůŝĐĂďůĞĂŐƌĞĞŵĞŶƚŽƌŐŽǀĞƌŶŝŶŐƌƵůĞƐĨŽƌƚŚĞ

ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ͘
Zϭ͘ϭ͘ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJŵĂLJ
ϰ͘Ϯ͘ ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ
ĞůĞĐƚƚŽĨƵůĨŝůůŝƚƐŽŶƚŝŶŐĞŶĐLJ
ZĞƐĞƌǀĞŽďůŝŐĂƚŝŽŶƐďLJ
ϭ͘ϰ͘ ĚĚŝƚŝŽŶĂůŽŵƉůŝĂŶĐĞ/ŶĨŽƌŵĂƚŝŽŶ
ƉĂƌƚŝĐŝƉĂƚŝŶŐĂƐĂŵĞŵďĞƌŽĨĂ
dŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJŵĂLJƵƐĞŽŶƚŝŶŐĞŶĐLJ
ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ͘/ŶƐƵĐŚ



3URMHFW%DODQFLQJ$XWKRULW\5HOLDELOLW\EDVHG
&RQWUROV5HVHUYHV
%$/'LVWXUEDQFH&RQWURO3HUIRUPDQFH
&RQWLQJHQF\5HVHUYHIRU5HFRYHU\IURPD%DODQFLQJ
&RQWLQJHQF\(YHQW0DSSLQJ'RFXPHQW



Ϯ 

ZĞƐĞƌǀĞĨŽƌĂŶLJĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚ
ĂƐƌĞƋƵŝƌĞĚĨŽƌĂŶLJŽƚŚĞƌĂƉƉůŝĐĂďůĞƐƚĂŶĚĂƌĚƐ͘

dŚŝƐƌĞƋƵŝƌĞŵĞŶƚĨĂůůƐƵŶĚĞƌƚŚĞWĂƌĂŐƌĂƉŚϴϭƌƵůĞƐ͘dŚŝƐ
ƌĞƋƵŝƌĞŵĞŶƚĚĞĨŝŶĞƐĂĐŽŵŵĞƌĐŝĂůĂŐƌĞĞŵĞŶƚďĞƚǁĞĞŶƚŚĞ
ŝŶǀŽůǀĞĚŝŶƚŚĞZ^'͘dŚŝƐƌĞƋƵŝƌĞŵĞŶƚĚŽĞƐŶŽƚƉƌŽǀŝĚĞĨŽƌĂŶ
ƌĞůŝĂďŝůŝƚLJŽƵƚĐŽŵĞĂŶĚŝĨǀŝŽůĂƚĞĚǁŽƵůĚŶŽƚĐĂƵƐĞƐĞƉĂƌĂƚŝŽŶ͕
ŝŶƐƚĂďŝůŝƚLJŽƌĐĂƐĐĂĚŝŶŐŽƵƚĂŐĞƐ͘

>ͲϬϬϮͲϮŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ


^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϬ
EZŽĂƌĚƉƉƌŽǀĞĚ
ĐĂƐĞƐ͕ƚŚĞZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ
ƐŚĂůůŚĂǀĞƚŚĞƐĂŵĞ
ƌĞƐƉŽŶƐŝďŝůŝƚŝĞƐĂŶĚŽďůŝŐĂƚŝŽŶƐĂƐ
ĞĂĐŚĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJǁŝƚŚ
ƌĞƐƉĞĐƚƚŽŵŽŶŝƚŽƌŝŶŐĂŶĚ
ŵĞĞƚŝŶŐƚŚĞƌĞƋƵŝƌĞŵĞŶƚƐŽĨ
^ƚĂŶĚĂƌĚ>ͲϬϬϮ͘dŚĞZĞůŝĂďŝůŝƚLJ
ŽŽƌĚŝŶĂƚŽƌĂŶĚWůĂŶŶŝŶŐ
ƵƚŚŽƌŝƚLJƐŚĂůůĞĂĐŚĞƐƚĂďůŝƐŚĂ
ƐĞƚŽĨŝŶƚĞƌͲƌĞŐŝŽŶĂůĂŶĚŝŶƚƌĂͲ
ƌĞŐŝŽŶĂůdƌĂŶƐĨĞƌĂƉĂďŝůŝƚŝĞƐ
ƚŚĂƚŝƐĐŽŶƐŝƐƚĞŶƚǁŝƚŚŝƚƐĐƵƌƌĞŶƚ
dƌĂŶƐĨĞƌĂƉĂďŝůŝƚLJDĞƚŚŽĚŽůŽŐLJ͘
ZϮ͘ ĂĐŚZĞŐŝŽŶĂůZĞůŝĂďŝůŝƚLJ
dŚŝƐZĞƋƵŝƌĞŵĞŶƚŚĂƐďĞĞŶ
KƌŐĂŶŝnjĂƚŝŽŶ͕ƐƵďͲZĞŐŝŽŶĂů
ƌĞŵŽǀĞĚĨƌŽŵ>ͲϬϬϮͲϮ
ZĞůŝĂďŝůŝƚLJKƌŐĂŶŝnjĂƚŝŽŶŽƌZĞƐĞƌǀĞ
^ŚĂƌŝŶŐ'ƌŽƵƉƐŚĂůůƐƉĞĐŝĨLJŝƚƐ
ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞƉŽůŝĐŝĞƐ͕
ŝŶĐůƵĚŝŶŐ͗

ZϮ͘ϭ͘dŚĞŵŝŶŝŵƵŵƌĞƐĞƌǀĞ
ƌĞƋƵŝƌĞŵĞŶƚĨŽƌƚŚĞŐƌŽƵƉ͘

ZϮ͘Ϯ͘/ƚƐĂůůŽĐĂƚŝŽŶĂŵŽŶŐ
ŵĞŵďĞƌƐ͘

>ͲϬϬϮͲϬDĂƉƉŝŶŐƚŽWƌŽƉŽƐĞĚEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ
ŽŵŵĞŶƚ
WƌŽƉŽƐĞĚ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ

>ͲϬϬϮͲϮŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ





ZϮ͘ϯ͘dŚĞƉĞƌŵŝƐƐŝďůĞŵŝdžŽĨ
KƉĞƌĂƚŝŶŐZĞƐĞƌǀĞʹ^ƉŝŶŶŝŶŐ
ĂŶĚKƉĞƌĂƚŝŶŐZĞƐĞƌǀĞʹ
^ƵƉƉůĞŵĞŶƚĂůƚŚĂƚŵĂLJďĞ
ŝŶĐůƵĚĞĚŝŶŽŶƚŝŶŐĞŶĐLJ
ZĞƐĞƌǀĞ͘

ZϮ͘ϰ͘dŚĞƉƌŽĐĞĚƵƌĞĨŽƌĂƉƉůLJŝŶŐ
ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞŝŶ
ƉƌĂĐƚŝĐĞ͘

ZϮ͘ϱ͘dŚĞůŝŵŝƚĂƚŝŽŶƐ͕ŝĨĂŶLJ͕ƵƉŽŶ
ƚŚĞĂŵŽƵŶƚŽĨŝŶƚĞƌƌƵƉƚŝďůĞ
ůŽĂĚƚŚĂƚŵĂLJďĞŝŶĐůƵĚĞĚ͘

ZϮ͘ϲ͘dŚĞƐĂŵĞƉŽƌƚŝŽŶŽĨƌĞƐŽƵƌĐĞ
ĐĂƉĂĐŝƚLJ;Ğ͘Ő͘ƌĞƐĞƌǀĞƐĨƌŽŵ
ũŽŝŶƚůLJŽǁŶĞĚŐĞŶĞƌĂƚŝŽŶͿ
ƐŚĂůůŶŽƚďĞĐŽƵŶƚĞĚŵŽƌĞ
ƚŚĂŶŽŶĐĞĂƐŽŶƚŝŶŐĞŶĐLJ
ZĞƐĞƌǀĞďLJŵƵůƚŝƉůĞĂůĂŶĐŝŶŐ
ƵƚŚŽƌŝƚŝĞƐ͘

^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϬ
EZŽĂƌĚƉƉƌŽǀĞĚ

>ͲϬϬϮͲϬDĂƉƉŝŶŐƚŽWƌŽƉŽƐĞĚEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ
ŽŵŵĞŶƚ
WƌŽƉŽƐĞĚ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ

ϯ 



Zϯ͘ϭ͘ƐĂŵŝŶŝŵƵŵ͕ƚŚĞĂůĂŶĐŝŶŐ
ƵƚŚŽƌŝƚLJŽƌZĞƐĞƌǀĞ
^ŚĂƌŝŶŐ'ƌŽƵƉƐŚĂůůĐĂƌƌLJĂƚ
ůĞĂƐƚĞŶŽƵŐŚŽŶƚŝŶŐĞŶĐLJ
ZĞƐĞƌǀĞƚŽĐŽǀĞƌƚŚĞŵŽƐƚ
ƐĞǀĞƌĞƐŝŶŐůĞĐŽŶƚŝŶŐĞŶĐLJ͘
ůůĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐ
ĂŶĚZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉƐ
ƐŚĂůůƌĞǀŝĞǁ͕ŶŽůĞƐƐ
ĨƌĞƋƵĞŶƚůLJƚŚĂŶĂŶŶƵĂůůLJ͕
ƚŚĞŝƌƉƌŽďĂďůĞ
ĐŽŶƚŝŶŐĞŶĐŝĞƐƚŽĚĞƚĞƌŵŝŶĞ
ƚŚĞŝƌƉƌŽƐƉĞĐƚŝǀĞŵŽƐƚ
ƐĞǀĞƌĞƐŝŶŐůĞĐŽŶƚŝŶŐĞŶĐŝĞƐ͘

ĂĐŚĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJŽƌ
ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉƐŚĂůů
ĂĐƚŝǀĂƚĞƐƵĨĨŝĐŝĞŶƚŽŶƚŝŶŐĞŶĐLJ
ZĞƐĞƌǀĞƚŽĐŽŵƉůLJǁŝƚŚƚŚĞ^͘

dŚŝƐZĞƋƵŝƌĞŵĞŶƚŚĂƐďĞĞŶ
ŵŽǀĞĚŝŶƚŽ>ͲϬϬϮͲϮ
ZĞƋƵŝƌĞŵĞŶƚƐZϭĂŶĚ
ZĞƋƵŝƌĞŵĞŶƚZϮ

•

&ƵƌƚŚĞƌƌĞĚƵĐĞĚďLJƚŚĞŵĂŐŶŝƚƵĚĞŽĨƚŚĞ
ĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶ;ŝͿƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛Ɛ
DŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;D^^ͿĂŶĚ;ŝŝͿ
ƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨƚŚĞZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚĂůůƉƌĞǀŝŽƵƐ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚŚĂǀĞŶŽƚ
ĐŽŵƉůĞƚĞĚƚŚĞŝƌŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ
ZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚǁŚĞŶƚŚĞƐƵŵƌĞĨĞƌĞŶĐĞĚŝŶ
o

ϰ 

ůĞƐƐƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨĂůů
ƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚ
ŽĐĐƵƌƉƌŝŽƌƚŽƚŚĂƚǀĂůƵĞŽĨZĞƉŽƌƚŝŶŐ
ǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕
ĂŶĚ
o

ĞƌŽ͕;ŝĨŝƚƐWƌĞͲZĞƉŽƌƚŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
sĂůƵĞǁĂƐƉŽƐŝƚŝǀĞŽƌĞƋƵĂůƚŽnjĞƌŽͿ͗

1. The Responsible Entity experiencing a Reportable
Balancing Contingency Event shall, within the
Contingency Event Recovery Period, return its ACE to at
least: [Violation Risk Factor: Medium][Time Horizon:
Real-time Operations]

ZĞƋƵŝƌĞŵĞŶƚZϭ

>ͲϬϬϮͲϮ

>ͲϬϬϮͲϮŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ


Zϯ͘

^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϬ
EZŽĂƌĚƉƉƌŽǀĞĚ

>ͲϬϬϮͲϬDĂƉƉŝŶŐƚŽWƌŽƉŽƐĞĚEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ
ŽŵŵĞŶƚ
WƌŽƉŽƐĞĚ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ

o &ƵƌƚŚĞƌƌĞĚƵĐĞĚďLJƚŚĞŵĂŐŶŝƚƵĚĞŽĨƚŚĞ
ĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶ;ŝͿƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛Ɛ
DŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;D^^ͿĂŶĚ;ŝŝͿ
ƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨƚŚĞZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚĂůůƉƌĞǀŝŽƵƐ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚŚĂǀĞŶŽƚ
ĐŽŵƉůĞƚĞĚƚŚĞŝƌŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ
ZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚǁŚĞŶƚŚĞƐƵŵƌĞĨĞƌĞŶĐĞĚŝŶ
ĐůĂƵƐĞ;ŝŝͿŽĨƚŚŝƐďƵůůĞƚŝƐŐƌĞĂƚĞƌƚŚĂŶD^^͘

o ůĞƐƐƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨĂůů
ƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚ
ŽĐĐƵƌƉƌŝŽƌƚŽƚŚĂƚǀĂůƵĞŽĨZĞƉŽƌƚŝŶŐ
ǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕
ĂŶĚ

/ƚƐWƌĞͲZĞƉŽƌƚŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞ͕;ŝĨ
ŝƚƐWƌĞͲZĞƉŽƌƚŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞǁĂƐ
ŶĞŐĂƚŝǀĞͿ͕

ĐůĂƵƐĞ;ŝŝͿŽĨƚŚŝƐďƵůůĞƚŝƐŐƌĞĂƚĞƌƚŚĂŶD^^͕

ϱ 

ϭ͘Ϯ͘ dŚŝƐƌĞƋƵŝƌĞŵĞŶƚ;ŝŶŝƚƐĞŶƚŝƌĞƚLJͿĚŽĞƐŶŽƚĂƉƉůLJ
ǁŚĞŶƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJĞdžƉĞƌŝĞŶĐŝŶŐĂ

ϭ͘ϭ͘dŚĞƌĞƋƵŝƌĞĚƌĞƉŽƌƚŝŶŐĨŽƌŵŝƐZ&Žƌŵϭ͘

•

Kƌ͕

>ͲϬϬϮͲϮŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ


^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϬ
EZŽĂƌĚƉƉƌŽǀĞĚ

>ͲϬϬϮͲϬDĂƉƉŝŶŐƚŽWƌŽƉŽƐĞĚEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ
ŽŵŵĞŶƚ
WƌŽƉŽƐĞĚ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ



ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJŽƌZĞƐĞƌǀĞ
^ŚĂƌŝŶŐ'ƌŽƵƉƐŚĂůůŵĞĞƚƚŚĞ
ŝƐƚƵƌďĂŶĐĞZĞĐŽǀĞƌLJƌŝƚĞƌŝŽŶ
ǁŝƚŚŝŶƚŚĞŝƐƚƵƌďĂŶĐĞZĞĐŽǀĞƌLJ
WĞƌŝŽĚĨŽƌϭϬϬйŽĨZĞƉŽƌƚĂďůĞ
ŝƐƚƵƌďĂŶĐĞƐ͘dŚĞŝƐƚƵƌďĂŶĐĞ
ZĞĐŽǀĞƌLJƌŝƚĞƌŝŽŶŝƐ͗

ZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚŝƐ
ĞdžƉĞƌŝĞŶĐŝŶŐĂŶŶĞƌŐLJŵĞƌŐĞŶĐLJůĞƌƚ>ĞǀĞůϮŽƌ
>ĞǀĞůϯ͘

•

ĞƌŽ͕;ŝĨŝƚƐWƌĞͲZĞƉŽƌƚŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ

ϲ 

dŚŝƐZĞƋƵŝƌĞŵĞŶƚŚĂƐďĞĞŶ
>ͲϬϬϮͲϬZĞƋƵŝƌĞŵĞŶƚZϰĂŶĚZϰ͘ϭƚŽ>ͲϬϬϮͲϮ
ŵŽǀĞĚŝŶƚŽ>ͲϬϬϮͲϮ
ZĞƋƵŝƌĞŵĞŶƚZϭ
ZĞƋƵŝƌĞŵĞŶƚZϭĂŶĚŝŶƚŽƚŚĞ
ϭ͘ dŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJĞdžƉĞƌŝĞŶĐŝŶŐĂZĞƉŽƌƚĂďůĞ
͞ŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐŚĂůů͕ǁŝƚŚŝŶƚŚĞ
WĞƌŝŽĚ͟ĂŶĚ͞ŽŶƚŝŶŐĞŶĐLJ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕ƌĞƚƵƌŶŝƚƐƚŽĂƚ
ZĞƐĞƌǀĞZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚ͟
ůĞĂƐƚ͗΀sŝŽůĂƚŝŽŶZŝƐŬ&ĂĐƚŽƌ͗DĞĚŝƵŵ΁΀dŝŵĞ,ŽƌŝnjŽŶ͗
ĚĞĨŝŶŝƚŝŽŶƐ͘
ZĞĂůͲƚŝŵĞKƉĞƌĂƚŝŽŶƐ΁



2. Except during the Contingency Event Recovery Period
and Contingency Reserve Restoration Period, or during
an Energy Emergency Alert Level 2 or Level 3, each
Responsible Entity shall maintain an amount of
Contingency Reserve at least equal to its Most Severe
Single Contingency.

ZĞƋƵŝƌĞŵĞŶƚZϮ

>ͲϬϬϭͲϮ



>ͲϬϬϮͲϮŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ


Zϰ͘

^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϬ
EZŽĂƌĚƉƉƌŽǀĞĚ

>ͲϬϬϮͲϬDĂƉƉŝŶŐƚŽWƌŽƉŽƐĞĚEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ
ŽŵŵĞŶƚ
WƌŽƉŽƐĞĚ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ



•

&ƵƌƚŚĞƌƌĞĚƵĐĞĚďLJƚŚĞŵĂŐŶŝƚƵĚĞŽĨƚŚĞ
ĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶ;ŝͿƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛Ɛ
DŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;D^^ͿĂŶĚ;ŝŝͿ
ƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨƚŚĞZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚĂůůƉƌĞǀŝŽƵƐ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚŚĂǀĞŶŽƚ
ĐŽŵƉůĞƚĞĚƚŚĞŝƌŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ
ZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚǁŚĞŶƚŚĞƐƵŵƌĞĨĞƌĞŶĐĞĚŝŶ
ĐůĂƵƐĞ;ŝŝͿŽĨƚŚŝƐďƵůůĞƚŝƐŐƌĞĂƚĞƌƚŚĂŶD^^͕
o

ϳ 

o ůĞƐƐƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨĂůů
ƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚ
ŽĐĐƵƌƉƌŝŽƌƚŽƚŚĂƚǀĂůƵĞŽĨZĞƉŽƌƚŝŶŐ
ǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕

/ƚƐWƌĞͲZĞƉŽƌƚŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞ͕;ŝĨ
ŝƚƐWƌĞͲZĞƉŽƌƚŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞǁĂƐ
ŶĞŐĂƚŝǀĞͿ͕

Kƌ͕

ůĞƐƐƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨĂůů
ƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚ
ŽĐĐƵƌƉƌŝŽƌƚŽƚŚĂƚǀĂůƵĞŽĨZĞƉŽƌƚŝŶŐ
ǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕
ĂŶĚ

o

sĂůƵĞǁĂƐƉŽƐŝƚŝǀĞŽƌĞƋƵĂůƚŽnjĞƌŽͿ͗

>ͲϬϬϮͲϮŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ


Zϰ͘Ϯ͘dŚĞĚĞĨĂƵůƚŝƐƚƵƌďĂŶĐĞ
ZĞĐŽǀĞƌLJWĞƌŝŽĚŝƐϭϱ
ŵŝŶƵƚĞƐĂĨƚĞƌƚŚĞƐƚĂƌƚŽĨĂ
ZĞƉŽƌƚĂďůĞŝƐƚƵƌďĂŶĐĞ͘
ĂĐŚĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ
ƐŚĂůůŚĂǀĞĂĐĐĞƐƐƚŽĂŶĚͬŽƌ
ŽƉĞƌĂƚĞŽŶƚŝŶŐĞŶĐLJ
ZĞƐĞƌǀĞƚŽƌĞƐƉŽŶĚƚŽ
ŝƐƚƵƌďĂŶĐĞƐ͘ŽŶƚŝŶŐĞŶĐLJ
ZĞƐĞƌǀĞŵĂLJďĞƐƵƉƉůŝĞĚ
ĨƌŽŵŐĞŶĞƌĂƚŝŽŶ͕
ĐŽŶƚƌŽůůĂďůĞůŽĂĚƌĞƐŽƵƌĐĞƐ͕

Zϰ͘ϭ͘ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJƐŚĂůů
ƌĞƚƵƌŶŝƚƐƚŽnjĞƌŽŝĨŝƚƐ
ũƵƐƚƉƌŝŽƌƚŽƚŚĞ
ZĞƉŽƌƚĂďůĞŝƐƚƵƌďĂŶĐĞǁĂƐ
ƉŽƐŝƚŝǀĞŽƌĞƋƵĂůƚŽnjĞƌŽ͘
&ŽƌŶĞŐĂƚŝǀĞŝŶŝƚŝĂů
ǀĂůƵĞƐũƵƐƚƉƌŝŽƌƚŽƚŚĞ
ŝƐƚƵƌďĂŶĐĞ͕ƚŚĞĂůĂŶĐŝŶŐ
ƵƚŚŽƌŝƚLJƐŚĂůůƌĞƚƵƌŶ
ƚŽŝƚƐƉƌĞͲŝƐƚƵƌďĂŶĐĞǀĂůƵĞ͘

^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϬ
EZŽĂƌĚƉƉƌŽǀĞĚ

>ͲϬϬϮͲϬDĂƉƉŝŶŐƚŽWƌŽƉŽƐĞĚEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ
ŽŵŵĞŶƚ
WƌŽƉŽƐĞĚ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ

o &ƵƌƚŚĞƌƌĞĚƵĐĞĚďLJƚŚĞŵĂŐŶŝƚƵĚĞŽĨƚŚĞ
ĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶ;ŝͿƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛Ɛ
DŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;D^^ͿĂŶĚ;ŝŝͿ
ƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨƚŚĞZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚĂůůƉƌĞǀŝŽƵƐ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚŚĂǀĞŶŽƚ
ĐŽŵƉůĞƚĞĚƚŚĞŝƌŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ
ZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚǁŚĞŶƚŚĞƐƵŵƌĞĨĞƌĞŶĐĞĚŝŶ
ĐůĂƵƐĞ;ŝŝͿŽĨƚŚŝƐďƵůůĞƚŝƐŐƌĞĂƚĞƌƚŚĂŶD^^͘

ĂŶĚ

ϴ 

ƉĞƌŝŽĚďĞŐŝŶŶŝŶŐĂƚƚŚĞƚŝŵĞƚŚĂƚƚŚĞƌĞƐŽƵƌĐĞ
ŽƵƚƉƵƚďĞŐŝŶƐƚŽĚĞĐůŝŶĞǁŝƚŚŝŶƚŚĞĨŝƌƐƚŽŶĞͲ
ŵŝŶƵƚĞŝŶƚĞƌǀĂůƚŚĂƚĚĞĨŝŶĞƐĂĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͕ĂŶĚĞdžƚĞŶĚƐĨŽƌĨŝĨƚĞĞŶŵŝŶƵƚĞƐ
ƚŚĞƌĞĂĨƚĞƌ͘

ŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ

ϭ͘Ϯ͘ dŚŝƐƌĞƋƵŝƌĞŵĞŶƚ;ŝŶŝƚƐĞŶƚŝƌĞƚLJͿĚŽĞƐŶŽƚĂƉƉůLJ
ǁŚĞŶƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJĞdžƉĞƌŝĞŶĐŝŶŐĂ
ZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚŝƐ
ĞdžƉĞƌŝĞŶĐŝŶŐĂŶŶĞƌŐLJŵĞƌŐĞŶĐLJůĞƌƚ>ĞǀĞůϮŽƌ
>ĞǀĞůϯ͘

ϭ͘ϭ͘dŚĞƌĞƋƵŝƌĞĚƌĞƉŽƌƚŝŶŐĨŽƌŵŝƐZ&Žƌŵϭ͘

>ͲϬϬϮͲϮŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ


^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϬ
EZŽĂƌĚƉƉƌŽǀĞĚ
ŽƌĐŽŽƌĚŝŶĂƚĞĚĂĚũƵƐƚŵĞŶƚƐ
ƚŽ/ŶƚĞƌĐŚĂŶŐĞ^ĐŚĞĚƵůĞƐ͘

>ͲϬϬϮͲϬDĂƉƉŝŶŐƚŽWƌŽƉŽƐĞĚEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ
ŽŵŵĞŶƚ
WƌŽƉŽƐĞĚ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ

•

&ƵƌƚŚĞƌƌĞĚƵĐĞĚďLJƚŚĞŵĂŐŶŝƚƵĚĞŽĨƚŚĞ
ĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶ;ŝͿƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛Ɛ
DŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;D^^ͿĂŶĚ;ŝŝͿ
ƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨƚŚĞZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚĂůůƉƌĞǀŝŽƵƐ
o

ϵ 

ůĞƐƐƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨĂůů
ƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚ
ŽĐĐƵƌƉƌŝŽƌƚŽƚŚĂƚǀĂůƵĞŽĨZĞƉŽƌƚŝŶŐ
ǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕
ĂŶĚ
o

ĞƌŽ͕;ŝĨŝƚƐWƌĞͲZĞƉŽƌƚŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
sĂůƵĞǁĂƐƉŽƐŝƚŝǀĞŽƌĞƋƵĂůƚŽnjĞƌŽͿ͗

ϭ͘ dŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJĞdžƉĞƌŝĞŶĐŝŶŐĂZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐŚĂůů͕ǁŝƚŚŝŶƚŚĞ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕ƌĞƚƵƌŶŝƚƐƚŽĂƚ
ůĞĂƐƚ͗΀sŝŽůĂƚŝŽŶZŝƐŬ&ĂĐƚŽƌ͗DĞĚŝƵŵ΁΀dŝŵĞ,ŽƌŝnjŽŶ͗
ZĞĂůͲƚŝŵĞKƉĞƌĂƚŝŽŶƐ΁

ZĞƋƵŝƌĞŵĞŶƚZϭ

>ͲϬϬϮͲϮ

ƉĞƌŝŽĚŶŽƚĞdžĐĞĞĚŝŶŐϵϬŵŝŶƵƚĞƐĨŽůůŽǁŝŶŐƚŚĞĞŶĚŽĨ
ƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͘

ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚ͗

>ͲϬϬϮͲϮŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ


Zϱ͘ ĂĐŚZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉƐŚĂůů dŚŝƐZĞƋƵŝƌĞŵĞŶƚŚĂƐďĞĞŶ
ĐŽŵƉůLJǁŝƚŚƚŚĞ^͘ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ
ŵŽǀĞĚŝŶƚŽ>ͲϬϬϮͲϮ
'ƌŽƵƉƐŚĂůůďĞĐŽŶƐŝĚĞƌĞĚŝŶĂ
ZĞƋƵŝƌĞŵĞŶƚZϭĂŶĚ
ZĞƉŽƌƚĂďůĞŝƐƚƵƌďĂŶĐĞĐŽŶĚŝƚŝŽŶ
ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ
ǁŚĞŶĞǀĞƌĂŐƌŽƵƉŵĞŵďĞƌŚĂƐ
ZĞƉŽƌƚŝŶŐ
ĞdžƉĞƌŝĞŶĐĞĚĂZĞƉŽƌƚĂďůĞŝƐƚƵƌďĂŶĐĞ
ĂŶĚĐĂůůƐĨŽƌƚŚĞĂĐƚŝǀĂƚŝŽŶŽĨ
ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞƐĨƌŽŵŽŶĞŽƌŵŽƌĞ
ŽƚŚĞƌŐƌŽƵƉŵĞŵďĞƌƐ͘;/ĨĂŐƌŽƵƉ
ŵĞŵďĞƌŚĂƐĞdžƉĞƌŝĞŶĐĞĚĂZĞƉŽƌƚĂďůĞ
ŝƐƚƵƌďĂŶĐĞďƵƚĚŽĞƐŶŽƚĐĂůůĨŽƌƌĞƐĞƌǀĞ
ĂĐƚŝǀĂƚŝŽŶĨƌŽŵŽƚŚĞƌŵĞŵďĞƌƐŽĨƚŚĞ
ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ͕ƚŚĞŶƚŚĂƚ
ŵĞŵďĞƌƐŚĂůůƌĞƉŽƌƚĂƐĂƐŝŶŐůĞ
ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͘ͿŽŵƉůŝĂŶĐĞŵĂLJ
ďĞĚĞŵŽŶƐƚƌĂƚĞĚďLJĞŝƚŚĞƌŽĨƚŚĞ
ĨŽůůŽǁŝŶŐƚǁŽŵĞƚŚŽĚƐ͗

Zϱ͘ϭ͘dŚĞZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ
ƌĞǀŝĞǁƐŐƌŽƵƉ;Žƌ
ĞƋƵŝǀĂůĞŶƚͿĂŶĚĚĞŵŽŶƐƚƌĂƚĞƐ

^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϬ
EZŽĂƌĚƉƉƌŽǀĞĚ

>ͲϬϬϮͲϬDĂƉƉŝŶŐƚŽWƌŽƉŽƐĞĚEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ
ŽŵŵĞŶƚ
WƌŽƉŽƐĞĚ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ

•

ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚŚĂǀĞŶŽƚ
ĐŽŵƉůĞƚĞĚƚŚĞŝƌŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ
ZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚǁŚĞŶƚŚĞƐƵŵƌĞĨĞƌĞŶĐĞĚŝŶ
ĐůĂƵƐĞ;ŝŝͿŽĨƚŚŝƐďƵůůĞƚŝƐŐƌĞĂƚĞƌƚŚĂŶD^^͕

ϭϬ

o &ƵƌƚŚĞƌƌĞĚƵĐĞĚďLJƚŚĞŵĂŐŶŝƚƵĚĞŽĨƚŚĞ
ĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶ;ŝͿƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛Ɛ
DŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;D^^ͿĂŶĚ;ŝŝͿ
ƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨƚŚĞZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚĂůůƉƌĞǀŝŽƵƐ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚŚĂǀĞŶŽƚ
ĐŽŵƉůĞƚĞĚƚŚĞŝƌŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ
ZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚǁŚĞŶƚŚĞƐƵŵƌĞĨĞƌĞŶĐĞĚŝŶ
ĐůĂƵƐĞ;ŝŝͿŽĨƚŚŝƐďƵůůĞƚŝƐŐƌĞĂƚĞƌƚŚĂŶD^^͘

o ůĞƐƐƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨĂůů
ƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚ
ŽĐĐƵƌƉƌŝŽƌƚŽƚŚĂƚǀĂůƵĞŽĨZĞƉŽƌƚŝŶŐ
ǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕
ĂŶĚ

/ƚƐWƌĞͲZĞƉŽƌƚŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞ͕;ŝĨ
ŝƚƐWƌĞͲZĞƉŽƌƚŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞǁĂƐ
ŶĞŐĂƚŝǀĞͿ͕

Kƌ͕

>ͲϬϬϮͲϮŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ


^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϬ
EZŽĂƌĚƉƉƌŽǀĞĚ
ĐŽŵƉůŝĂŶĐĞƚŽƚŚĞ^͘dŽďĞŝŶ
ĐŽŵƉůŝĂŶĐĞ͕ƚŚĞŐƌŽƵƉ;ŽƌŝƚƐ
ĞƋƵŝǀĂůĞŶƚͿŵƵƐƚŵĞĞƚƚŚĞ
ŝƐƚƵƌďĂŶĐĞZĞĐŽǀĞƌLJƌŝƚĞƌŝŽŶ
ĂĨƚĞƌƚŚĞƐĐŚĞĚƵůĞĐŚĂŶŐĞ;ƐͿ
ƌĞůĂƚĞĚƚŽƌĞƐĞƌǀĞƐŚĂƌŝŶŐŚĂǀĞ
ďĞĞŶĨƵůůLJŝŵƉůĞŵĞŶƚĞĚ͕ĂŶĚ
ǁŝƚŚŝŶƚŚĞŝƐƚƵƌďĂŶĐĞZĞĐŽǀĞƌLJ
WĞƌŝŽĚ͘

Žƌ

Zϱ͘Ϯ͘dŚĞZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ
ƌĞǀŝĞǁƐĞĂĐŚŵĞŵďĞƌ͛ƐŝŶ
ƌĞƐƉŽŶƐĞƚŽƚŚĞĂĐƚŝǀĂƚŝŽŶŽĨ
ƌĞƐĞƌǀĞƐ͘dŽďĞŝŶĐŽŵƉůŝĂŶĐĞ͕Ă
ŵĞŵďĞƌ͛Ɛ;ŽƌŝƚƐĞƋƵŝǀĂůĞŶƚͿ
ŵƵƐƚŵĞĞƚƚŚĞŝƐƚƵƌďĂŶĐĞ
ZĞĐŽǀĞƌLJƌŝƚĞƌŝŽŶĂĨƚĞƌƚŚĞ
ƐĐŚĞĚƵůĞĐŚĂŶŐĞ;ƐͿƌĞůĂƚĞĚƚŽ
ƌĞƐĞƌǀĞƐŚĂƌŝŶŐŚĂǀĞďĞĞŶĨƵůůLJ
ŝŵƉůĞŵĞŶƚĞĚ͕ĂŶĚǁŝƚŚŝŶƚŚĞ
ŝƐƚƵƌďĂŶĐĞZĞĐŽǀĞƌLJWĞƌŝŽĚ͘

>ͲϬϬϮͲϬDĂƉƉŝŶŐƚŽWƌŽƉŽƐĞĚEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ
ŽŵŵĞŶƚ
WƌŽƉŽƐĞĚ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ





Zϲ͘ϭ͘dŚĞŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ

ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJŽƌZĞƐĞƌǀĞ
^ŚĂƌŝŶŐ'ƌŽƵƉƐŚĂůůĨƵůůLJƌĞƐƚŽƌĞ
ŝƚƐŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞƐǁŝƚŚŝŶ
ƚŚĞŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ
ZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚĨŽƌŝƚƐ
/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͘

ϭϭ

dŚŝƐZĞƋƵŝƌĞŵĞŶƚŚĂƐďĞĞŶ
>ͲϬϬϮͲϮ
ŵŽǀĞĚŝŶƚŽƚŚĞ>ͲϬϬϮͲϮ

ZĞƋƵŝƌĞŵĞŶƚZϭĂŶĚ
ZĞƋƵŝƌĞŵĞŶƚZϭ
͞ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
ZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚ͟ĚĞĨŝŶŝƚŝŽŶ
ϭ͘ dŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJĞdžƉĞƌŝĞŶĐŝŶŐĂZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐŚĂůů͕ǁŝƚŚŝŶƚŚĞ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕ƌĞƚƵƌŶŝƚƐƚŽĂƚ
ůĞĂƐƚ͗΀sŝŽůĂƚŝŽŶZŝƐŬ&ĂĐƚŽƌ͗DĞĚŝƵŵ΁΀dŝŵĞ,ŽƌŝnjŽŶ͗



ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉZĞƉŽƌƚŝŶŐ
ƚĂŶLJŐŝǀĞŶƚŝŵĞŽĨŵĞĂƐƵƌĞŵĞŶƚĨŽƌƚŚĞ
ĂƉƉůŝĐĂďůĞZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ͕ƚŚĞĂůŐĞďƌĂŝĐ
ƐƵŵŽĨƚŚĞƐ;ĂƐĐĂůĐƵůĂƚĞĚĂƚƐƵĐŚƚŝŵĞŽĨ
ŵĞĂƐƵƌĞŵĞŶƚͿŽĨĂůůŽĨƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐ
ƚŚĂƚŵĂŬĞƵƉƚŚĞZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ͘



ϭ͘Ϯ͘ dŚŝƐƌĞƋƵŝƌĞŵĞŶƚ;ŝŶŝƚƐĞŶƚŝƌĞƚLJͿĚŽĞƐŶŽƚĂƉƉůLJ
ǁŚĞŶƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJĞdžƉĞƌŝĞŶĐŝŶŐĂ
ZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚŝƐ
ĞdžƉĞƌŝĞŶĐŝŶŐĂŶŶĞƌŐLJŵĞƌŐĞŶĐLJůĞƌƚ>ĞǀĞůϮŽƌ
>ĞǀĞůϯ͘

ϭ͘ϭ͘dŚĞƌĞƋƵŝƌĞĚƌĞƉŽƌƚŝŶŐĨŽƌŵŝƐZ&Žƌŵϭ͘

>ͲϬϬϮͲϮŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ


Zϲ͘

^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϬ
EZŽĂƌĚƉƉƌŽǀĞĚ

>ͲϬϬϮͲϬDĂƉƉŝŶŐƚŽWƌŽƉŽƐĞĚEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ
ŽŵŵĞŶƚ
WƌŽƉŽƐĞĚ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ





•

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&ƵƌƚŚĞƌƌĞĚƵĐĞĚďLJƚŚĞŵĂŐŶŝƚƵĚĞŽĨƚŚĞ
ĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶ;ŝͿƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛Ɛ
DŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;D^^ͿĂŶĚ;ŝŝͿ
ƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨƚŚĞZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚĂůůƉƌĞǀŝŽƵƐ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚŚĂǀĞŶŽƚ
ĐŽŵƉůĞƚĞĚƚŚĞŝƌŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ
ZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚǁŚĞŶƚŚĞƐƵŵƌĞĨĞƌĞŶĐĞĚŝŶ
ĐůĂƵƐĞ;ŝŝͿŽĨƚŚŝƐďƵůůĞƚŝƐŐƌĞĂƚĞƌƚŚĂŶD^^͕
o

o ůĞƐƐƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨĂůů

ϭϮ

/ƚƐWƌĞͲZĞƉŽƌƚŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞ͕;ŝĨ
ŝƚƐWƌĞͲZĞƉŽƌƚŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞǁĂƐ
ŶĞŐĂƚŝǀĞͿ͕

Kƌ͕

ůĞƐƐƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨĂůů
ƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚ
ŽĐĐƵƌƉƌŝŽƌƚŽƚŚĂƚǀĂůƵĞŽĨZĞƉŽƌƚŝŶŐ
ǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕
ĂŶĚ

o

ĞƌŽ͕;ŝĨŝƚƐWƌĞͲZĞƉŽƌƚŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
sĂůƵĞǁĂƐƉŽƐŝƚŝǀĞŽƌĞƋƵĂůƚŽnjĞƌŽͿ͗

ZĞĂůͲƚŝŵĞKƉĞƌĂƚŝŽŶƐ΁

>ͲϬϬϮͲϮŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ


Zϲ͘Ϯ͘dŚĞĚĞĨĂƵůƚŽŶƚŝŶŐĞŶĐLJ
ZĞƐĞƌǀĞZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚ
ŝƐϵϬŵŝŶƵƚĞƐ͘

^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϬ
EZŽĂƌĚƉƉƌŽǀĞĚ
ZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚďĞŐŝŶƐĂƚ
ƚŚĞĞŶĚŽĨƚŚĞŝƐƚƵƌďĂŶĐĞ
ZĞĐŽǀĞƌLJWĞƌŝŽĚ͘

>ͲϬϬϮͲϬDĂƉƉŝŶŐƚŽWƌŽƉŽƐĞĚEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ
ŽŵŵĞŶƚ
WƌŽƉŽƐĞĚ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ





ϭϯ

ϭ͘Ϯ͘ dŚŝƐƌĞƋƵŝƌĞŵĞŶƚ;ŝŶŝƚƐĞŶƚŝƌĞƚLJͿĚŽĞƐŶŽƚĂƉƉůLJ
ǁŚĞŶƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJĞdžƉĞƌŝĞŶĐŝŶŐĂ
ZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚŝƐ
ĞdžƉĞƌŝĞŶĐŝŶŐĂŶŶĞƌŐLJŵĞƌŐĞŶĐLJůĞƌƚ>ĞǀĞůϮŽƌ
>ĞǀĞůϯ͘

ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚ͗



o &ƵƌƚŚĞƌƌĞĚƵĐĞĚďLJƚŚĞŵĂŐŶŝƚƵĚĞŽĨƚŚĞ
ĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶ;ŝͿƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛Ɛ
DŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;D^^ͿĂŶĚ;ŝŝͿ
ƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨƚŚĞZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚĂůůƉƌĞǀŝŽƵƐ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚŚĂǀĞŶŽƚ
ĐŽŵƉůĞƚĞĚƚŚĞŝƌŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ
ZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚǁŚĞŶƚŚĞƐƵŵƌĞĨĞƌĞŶĐĞĚŝŶ
ĐůĂƵƐĞ;ŝŝͿŽĨƚŚŝƐďƵůůĞƚŝƐŐƌĞĂƚĞƌƚŚĂŶD^^͘

ƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚ
ŽĐĐƵƌƉƌŝŽƌƚŽƚŚĂƚǀĂůƵĞŽĨZĞƉŽƌƚŝŶŐ
ǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕
ĂŶĚ

ϭ͘ϭ͘dŚĞƌĞƋƵŝƌĞĚƌĞƉŽƌƚŝŶŐĨŽƌŵŝƐZ&Žƌŵϭ͘

>ͲϬϬϮͲϮŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ


^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϬ
EZŽĂƌĚƉƉƌŽǀĞĚ

>ͲϬϬϮͲϬDĂƉƉŝŶŐƚŽWƌŽƉŽƐĞĚEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ
ŽŵŵĞŶƚ
WƌŽƉŽƐĞĚ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ











>ͲϬϬϮͲϮŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ


^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϬ
EZŽĂƌĚƉƉƌŽǀĞĚ



ϭϰ

ƉĞƌŝŽĚŶŽƚĞdžĐĞĞĚŝŶŐϵϬŵŝŶƵƚĞƐĨŽůůŽǁŝŶŐƚŚĞĞŶĚŽĨ
ƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͘

>ͲϬϬϮͲϬDĂƉƉŝŶŐƚŽWƌŽƉŽƐĞĚEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ
ŽŵŵĞŶƚ
WƌŽƉŽƐĞĚ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ



>ͲϬϬϮͲϬDĂƉƉŝŶŐƚŽWƌŽƉŽƐĞĚEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ
^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϬ
ŽŵŵĞŶƚ
WƌŽƉŽƐĞĚ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ
EZŽĂƌĚƉƉƌŽǀĞĚ
Zϭ͘ ĂĐŚĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJƐŚĂůů
dŚŝƐZĞƋƵŝƌĞŵĞŶƚŚĂƐďĞĞŶ
ƉƉůŝĐĂďŝůŝƚLJ
ŚĂǀĞĂĐĐĞƐƐƚŽĂŶĚͬŽƌŽƉĞƌĂƚĞ
ŵŽǀĞĚŝŶƚŽ>ͲϬϬϮͲϮ
ϰ͘ϭ͘ ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ
ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞƚŽƌĞƐƉŽŶĚƚŽ
ƉƉůŝĐĂďŝůŝƚLJĂŶĚ͞ĚĚŝƚŝŽŶĂů
ŝƐƚƵƌďĂŶĐĞƐ͘ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞŵĂLJ ŽŵƉůŝĂŶĐĞ/ŶĨŽƌŵĂƚŝŽŶ͟
ϰ͘ϭ͘ϭ ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJƚŚĂƚŝƐĂŵĞŵďĞƌŽĨĂ
ďĞƐƵƉƉůŝĞĚĨƌŽŵŐĞŶĞƌĂƚŝŽŶ͕
ƐĞĐƚŝŽŶƐ
ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉŝƐƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ
ĐŽŶƚƌŽůůĂďůĞůŽĂĚƌĞƐŽƵƌĐĞƐ͕Žƌ
ŽŶůLJŝŶƉĞƌŝŽĚƐĚƵƌŝŶŐǁŚŝĐŚƚŚĞĂůĂŶĐŝŶŐ
ĐŽŽƌĚŝŶĂƚĞĚĂĚũƵƐƚŵĞŶƚƐƚŽ/ŶƚĞƌĐŚĂŶŐĞ
ƵƚŚŽƌŝƚLJŝƐŶŽƚŝŶĂĐƚŝǀĞƐƚĂƚƵƐƵŶĚĞƌƚŚĞ
^ĐŚĞĚƵůĞƐ͘
ĂƉƉůŝĐĂďůĞĂŐƌĞĞŵĞŶƚŽƌŐŽǀĞƌŶŝŶŐƌƵůĞƐĨŽƌƚŚĞ

ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ͘
Zϭ͘ϭ͘ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJŵĂLJ
ϰ͘Ϯ͘ ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ
ĞůĞĐƚƚŽĨƵůĨŝůůŝƚƐŽŶƚŝŶŐĞŶĐLJ
ZĞƐĞƌǀĞŽďůŝŐĂƚŝŽŶƐďLJ
ϭ͘ϰ͘ ĚĚŝƚŝŽŶĂůŽŵƉůŝĂŶĐĞ/ŶĨŽƌŵĂƚŝŽŶ
ƉĂƌƚŝĐŝƉĂƚŝŶŐĂƐĂŵĞŵďĞƌŽĨĂ
dŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJŵĂLJƵƐĞŽŶƚŝŶŐĞŶĐLJ
ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ͘/ŶƐƵĐŚ



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ZĞƐĞƌǀĞĨŽƌĂŶLJĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚ
ĂƐƌĞƋƵŝƌĞĚĨŽƌĂŶLJŽƚŚĞƌĂƉƉůŝĐĂďůĞƐƚĂŶĚĂƌĚƐ͘

dŚŝƐƌĞƋƵŝƌĞŵĞŶƚĨĂůůƐƵŶĚĞƌƚŚĞWĂƌĂŐƌĂƉŚϴϭƌƵůĞƐ͘dŚŝƐ
ƌĞƋƵŝƌĞŵĞŶƚĚĞĨŝŶĞƐĂĐŽŵŵĞƌĐŝĂůĂŐƌĞĞŵĞŶƚďĞƚǁĞĞŶƚŚĞ
ŝŶǀŽůǀĞĚŝŶƚŚĞZ^'͘dŚŝƐƌĞƋƵŝƌĞŵĞŶƚĚŽĞƐŶŽƚƉƌŽǀŝĚĞĨŽƌĂŶ
ƌĞůŝĂďŝůŝƚLJŽƵƚĐŽŵĞĂŶĚŝĨǀŝŽůĂƚĞĚǁŽƵůĚŶŽƚĐĂƵƐĞƐĞƉĂƌĂƚŝŽŶ͕
ŝŶƐƚĂďŝůŝƚLJŽƌĐĂƐĐĂĚŝŶŐŽƵƚĂŐĞƐ͘

>ͲϬϬϮͲϮŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ


^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϬ
EZŽĂƌĚƉƉƌŽǀĞĚ
ĐĂƐĞƐ͕ƚŚĞZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ
ƐŚĂůůŚĂǀĞƚŚĞƐĂŵĞ
ƌĞƐƉŽŶƐŝďŝůŝƚŝĞƐĂŶĚŽďůŝŐĂƚŝŽŶƐĂƐ
ĞĂĐŚĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJǁŝƚŚ
ƌĞƐƉĞĐƚƚŽŵŽŶŝƚŽƌŝŶŐĂŶĚ
ŵĞĞƚŝŶŐƚŚĞƌĞƋƵŝƌĞŵĞŶƚƐŽĨ
^ƚĂŶĚĂƌĚ>ͲϬϬϮ͘dŚĞZĞůŝĂďŝůŝƚLJ
ŽŽƌĚŝŶĂƚŽƌĂŶĚWůĂŶŶŝŶŐ
ƵƚŚŽƌŝƚLJƐŚĂůůĞĂĐŚĞƐƚĂďůŝƐŚĂ
ƐĞƚŽĨŝŶƚĞƌͲƌĞŐŝŽŶĂůĂŶĚŝŶƚƌĂͲ
ƌĞŐŝŽŶĂůdƌĂŶƐĨĞƌĂƉĂďŝůŝƚŝĞƐ
ƚŚĂƚŝƐĐŽŶƐŝƐƚĞŶƚǁŝƚŚŝƚƐĐƵƌƌĞŶƚ
dƌĂŶƐĨĞƌĂƉĂďŝůŝƚLJDĞƚŚŽĚŽůŽŐLJ͘
ZϮ͘ ĂĐŚZĞŐŝŽŶĂůZĞůŝĂďŝůŝƚLJ
dŚŝƐZĞƋƵŝƌĞŵĞŶƚŚĂƐďĞĞŶ
KƌŐĂŶŝnjĂƚŝŽŶ͕ƐƵďͲZĞŐŝŽŶĂů
ƌĞŵŽǀĞĚĨƌŽŵ>ͲϬϬϮͲϮ
ZĞůŝĂďŝůŝƚLJKƌŐĂŶŝnjĂƚŝŽŶŽƌZĞƐĞƌǀĞ
^ŚĂƌŝŶŐ'ƌŽƵƉƐŚĂůůƐƉĞĐŝĨLJŝƚƐ
ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞƉŽůŝĐŝĞƐ͕
ŝŶĐůƵĚŝŶŐ͗

ZϮ͘ϭ͘dŚĞŵŝŶŝŵƵŵƌĞƐĞƌǀĞ
ƌĞƋƵŝƌĞŵĞŶƚĨŽƌƚŚĞŐƌŽƵƉ͘

ZϮ͘Ϯ͘/ƚƐĂůůŽĐĂƚŝŽŶĂŵŽŶŐ
ŵĞŵďĞƌƐ͘

>ͲϬϬϮͲϬDĂƉƉŝŶŐƚŽWƌŽƉŽƐĞĚEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ
ŽŵŵĞŶƚ
WƌŽƉŽƐĞĚ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ

>ͲϬϬϮͲϮŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ





ZϮ͘ϯ͘dŚĞƉĞƌŵŝƐƐŝďůĞŵŝdžŽĨ
KƉĞƌĂƚŝŶŐZĞƐĞƌǀĞʹ^ƉŝŶŶŝŶŐ
ĂŶĚKƉĞƌĂƚŝŶŐZĞƐĞƌǀĞʹ
^ƵƉƉůĞŵĞŶƚĂůƚŚĂƚŵĂLJďĞ
ŝŶĐůƵĚĞĚŝŶŽŶƚŝŶŐĞŶĐLJ
ZĞƐĞƌǀĞ͘

ZϮ͘ϰ͘dŚĞƉƌŽĐĞĚƵƌĞĨŽƌĂƉƉůLJŝŶŐ
ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞŝŶ
ƉƌĂĐƚŝĐĞ͘

ZϮ͘ϱ͘dŚĞůŝŵŝƚĂƚŝŽŶƐ͕ŝĨĂŶLJ͕ƵƉŽŶ
ƚŚĞĂŵŽƵŶƚŽĨŝŶƚĞƌƌƵƉƚŝďůĞ
ůŽĂĚƚŚĂƚŵĂLJďĞŝŶĐůƵĚĞĚ͘

ZϮ͘ϲ͘dŚĞƐĂŵĞƉŽƌƚŝŽŶŽĨƌĞƐŽƵƌĐĞ
ĐĂƉĂĐŝƚLJ;Ğ͘Ő͘ƌĞƐĞƌǀĞƐĨƌŽŵ
ũŽŝŶƚůLJŽǁŶĞĚŐĞŶĞƌĂƚŝŽŶͿ
ƐŚĂůůŶŽƚďĞĐŽƵŶƚĞĚŵŽƌĞ
ƚŚĂŶŽŶĐĞĂƐŽŶƚŝŶŐĞŶĐLJ
ZĞƐĞƌǀĞďLJŵƵůƚŝƉůĞĂůĂŶĐŝŶŐ
ƵƚŚŽƌŝƚŝĞƐ͘

^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϬ
EZŽĂƌĚƉƉƌŽǀĞĚ

>ͲϬϬϮͲϬDĂƉƉŝŶŐƚŽWƌŽƉŽƐĞĚEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ
ŽŵŵĞŶƚ
WƌŽƉŽƐĞĚ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ

ϯ 



Zϯ͘ϭ͘ƐĂŵŝŶŝŵƵŵ͕ƚŚĞĂůĂŶĐŝŶŐ
ƵƚŚŽƌŝƚLJŽƌZĞƐĞƌǀĞ
^ŚĂƌŝŶŐ'ƌŽƵƉƐŚĂůůĐĂƌƌLJĂƚ
ůĞĂƐƚĞŶŽƵŐŚŽŶƚŝŶŐĞŶĐLJ
ZĞƐĞƌǀĞƚŽĐŽǀĞƌƚŚĞŵŽƐƚ
ƐĞǀĞƌĞƐŝŶŐůĞĐŽŶƚŝŶŐĞŶĐLJ͘
ůůĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐ
ĂŶĚZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉƐ
ƐŚĂůůƌĞǀŝĞǁ͕ŶŽůĞƐƐ
ĨƌĞƋƵĞŶƚůLJƚŚĂŶĂŶŶƵĂůůLJ͕
ƚŚĞŝƌƉƌŽďĂďůĞ
ĐŽŶƚŝŶŐĞŶĐŝĞƐƚŽĚĞƚĞƌŵŝŶĞ
ƚŚĞŝƌƉƌŽƐƉĞĐƚŝǀĞŵŽƐƚ
ƐĞǀĞƌĞƐŝŶŐůĞĐŽŶƚŝŶŐĞŶĐŝĞƐ͘

ĂĐŚĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJŽƌ
ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉƐŚĂůů
ĂĐƚŝǀĂƚĞƐƵĨĨŝĐŝĞŶƚŽŶƚŝŶŐĞŶĐLJ
ZĞƐĞƌǀĞƚŽĐŽŵƉůLJǁŝƚŚƚŚĞ^͘

dŚŝƐZĞƋƵŝƌĞŵĞŶƚŚĂƐďĞĞŶ
ŵŽǀĞĚŝŶƚŽ>ͲϬϬϮͲϮ
ZĞƋƵŝƌĞŵĞŶƚƐZϭĂŶĚ
ZĞƋƵŝƌĞŵĞŶƚZϮ

•

&ƵƌƚŚĞƌƌĞĚƵĐĞĚďLJƚŚĞŵĂŐŶŝƚƵĚĞŽĨƚŚĞ
ĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶ;ŝͿƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛Ɛ
DŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;D^^ͿĂŶĚ;ŝŝͿ
ƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨƚŚĞZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚĂůůƉƌĞǀŝŽƵƐ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚŚĂǀĞŶŽƚ
ĐŽŵƉůĞƚĞĚƚŚĞŝƌŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ
ZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚǁŚĞŶƚŚĞƐƵŵƌĞĨĞƌĞŶĐĞĚŝŶ
o

ϰ 

ůĞƐƐƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨĂůů
ƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚ
ŽĐĐƵƌƉƌŝŽƌƚŽƚŚĂƚǀĂůƵĞŽĨZĞƉŽƌƚŝŶŐ
ǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕
ĂŶĚ
o

ĞƌŽ͕;ŝĨŝƚƐWƌĞͲZĞƉŽƌƚŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
sĂůƵĞǁĂƐƉŽƐŝƚŝǀĞŽƌĞƋƵĂůƚŽnjĞƌŽͿ͗

1. The Responsible Entity experiencing a Reportable
Balancing Contingency Event shall, within the
Contingency Event Recovery Period, return its ACE to at
least: [Violation Risk Factor: Medium][Time Horizon:
Real-time Operations]

ZĞƋƵŝƌĞŵĞŶƚZϭ

>ͲϬϬϮͲϮ

>ͲϬϬϮͲϮŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ


Zϯ͘

^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϬ
EZŽĂƌĚƉƉƌŽǀĞĚ

>ͲϬϬϮͲϬDĂƉƉŝŶŐƚŽWƌŽƉŽƐĞĚEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ
ŽŵŵĞŶƚ
WƌŽƉŽƐĞĚ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ

o &ƵƌƚŚĞƌƌĞĚƵĐĞĚďLJƚŚĞŵĂŐŶŝƚƵĚĞŽĨƚŚĞ
ĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶ;ŝͿƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛Ɛ
DŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;D^^ͿĂŶĚ;ŝŝͿ
ƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨƚŚĞZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚĂůůƉƌĞǀŝŽƵƐ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚŚĂǀĞŶŽƚ
ĐŽŵƉůĞƚĞĚƚŚĞŝƌŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ
ZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚǁŚĞŶƚŚĞƐƵŵƌĞĨĞƌĞŶĐĞĚŝŶ
ĐůĂƵƐĞ;ŝŝͿŽĨƚŚŝƐďƵůůĞƚŝƐŐƌĞĂƚĞƌƚŚĂŶD^^͘

o ůĞƐƐƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨĂůů
ƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚ
ŽĐĐƵƌƉƌŝŽƌƚŽƚŚĂƚǀĂůƵĞŽĨZĞƉŽƌƚŝŶŐ
ǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕
ĂŶĚ

/ƚƐWƌĞͲZĞƉŽƌƚŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞ͕;ŝĨ
ŝƚƐWƌĞͲZĞƉŽƌƚŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞǁĂƐ
ŶĞŐĂƚŝǀĞͿ͕

ĐůĂƵƐĞ;ŝŝͿŽĨƚŚŝƐďƵůůĞƚŝƐŐƌĞĂƚĞƌƚŚĂŶD^^͕

ϱ 

ϭ͘Ϯ͘ dŚŝƐƌĞƋƵŝƌĞŵĞŶƚ;ŝŶŝƚƐĞŶƚŝƌĞƚLJͿĚŽĞƐŶŽƚĂƉƉůLJ
ǁŚĞŶƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJĞdžƉĞƌŝĞŶĐŝŶŐĂ

ϭ͘ϭ͘dŚĞƌĞƋƵŝƌĞĚƌĞƉŽƌƚŝŶŐĨŽƌŵŝƐZ&Žƌŵϭ͘

•

Kƌ͕

>ͲϬϬϮͲϮŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ


^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϬ
EZŽĂƌĚƉƉƌŽǀĞĚ

>ͲϬϬϮͲϬDĂƉƉŝŶŐƚŽWƌŽƉŽƐĞĚEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ
ŽŵŵĞŶƚ
WƌŽƉŽƐĞĚ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ

ZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚŝƐ
ĞdžƉĞƌŝĞŶĐŝŶŐĂŶŶĞƌŐLJŵĞƌŐĞŶĐLJůĞƌƚ>ĞǀĞůϮŽƌ
>ĞǀĞůϯ͘

•

ĨƵƌƚŚĞƌƌĞĚƵĐĞĚďLJƚŚĞŵĂŐŶŝƚƵĚĞŽĨƚŚĞ
ĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶ;ŝͿƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛Ɛ
DŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;D^^ͿĂŶĚ;ŝŝͿ
ƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨƚŚĞZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚĂůůƉƌĞǀŝŽƵƐ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚŚĂǀĞŶŽƚ
ĐŽŵƉůĞƚĞĚƚŚĞŝƌŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞƐƚŽƌĂƚŝŽŶ
WĞƌŝŽĚǁŚĞŶƚŚĞƐƵŵƌĞĨĞƌĞŶĐĞĚŝŶĐůĂƵƐĞ;ŝŝͿ
ŽĨƚŚŝƐďƵůůĞƚŝƐŐƌĞĂƚĞƌƚŚĂŶD^^͕
o

ϲ 

ůĞƐƐƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨĂůů
ƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚ
ŽĐĐƵƌǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJ
WĞƌŝŽĚ͕ĂŶĚ
o

ĞƌŽ͕;ŝĨŝƚƐWƌĞͲZĞƉŽƌƚĂďůĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
sĂůƵĞǁĂƐƉŽƐŝƚŝǀĞŽƌĞƋƵĂůƚŽnjĞƌŽͿ͗

ϭ͘ džĐĞƉƚǁŚĞŶĂŶŶĞƌŐLJŵĞƌŐĞŶĐLJůĞƌƚ>ĞǀĞůϮŽƌϯŝƐŝŶ
ĞĨĨĞĐƚ͕ƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJĞdžƉĞƌŝĞŶĐŝŶŐĂZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐŚĂůůĚĞŵŽŶƐƚƌĂƚĞƚŚĂƚ
ǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚƚŚĞ
ZĞƐƉŽŶƐŝďůĞŶƚŝƚLJƌĞƚƵƌŶĞĚŝƚƐƚŽ͗

>ͲϬϬϮͲϮŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ


^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϬ
EZŽĂƌĚƉƉƌŽǀĞĚ

>ͲϬϬϮͲϬDĂƉƉŝŶŐƚŽWƌŽƉŽƐĞĚEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ
ŽŵŵĞŶƚ
WƌŽƉŽƐĞĚ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ

2. Except during the Contingency Event Recovery Period

ϳ 

o &ƵƌƚŚĞƌƌĞĚƵĐĞĚďLJƚŚĞŵĂŐŶŝƚƵĚĞŽĨƚŚĞ
ĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶ;ŝͿƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛Ɛ
DŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;D^^ͿĂŶĚ
;ŝŝͿƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨƚŚĞ
ZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚ
ĂůůƉƌĞǀŝŽƵƐĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚ
ŚĂǀĞŶŽƚĐŽŵƉůĞƚĞĚƚŚĞŝƌŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
ZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚǁŚĞŶƚŚĞƐƵŵƌĞĨĞƌĞŶĐĞĚ
ŝŶĐůĂƵƐĞ;ŝŝͿŽĨƚŚŝƐďƵůůĞƚŝƐŐƌĞĂƚĞƌƚŚĂŶ
D^^͘

o >ĞƐƐƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞŽĨĂůů
ƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚ
ŽĐĐƵƌǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJ
WĞƌŝŽĚ͕ĂŶĚ

/ƚƐWƌĞͲZĞƉŽƌƚĂďůĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞ͕;ŝĨ
ŝƚƐWƌĞͲZĞƉŽƌƚĂďůĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞǁĂƐ
ŶĞŐĂƚŝǀĞͿ͗

Kƌ͕

ZĞƋƵŝƌĞŵĞŶƚZϮ

>ͲϬϬϭͲϮ



•

>ͲϬϬϮͲϮŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ


^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϬ
EZŽĂƌĚƉƉƌŽǀĞĚ

>ͲϬϬϮͲϬDĂƉƉŝŶŐƚŽWƌŽƉŽƐĞĚEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ
ŽŵŵĞŶƚ
WƌŽƉŽƐĞĚ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ



Zϰ͘ϭ͘ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJƐŚĂůů
ƌĞƚƵƌŶŝƚƐƚŽnjĞƌŽŝĨŝƚƐ
ũƵƐƚƉƌŝŽƌƚŽƚŚĞ
ZĞƉŽƌƚĂďůĞŝƐƚƵƌďĂŶĐĞǁĂƐ
ƉŽƐŝƚŝǀĞŽƌĞƋƵĂůƚŽnjĞƌŽ͘
&ŽƌŶĞŐĂƚŝǀĞŝŶŝƚŝĂů
ǀĂůƵĞƐũƵƐƚƉƌŝŽƌƚŽƚŚĞ
ŝƐƚƵƌďĂŶĐĞ͕ƚŚĞĂůĂŶĐŝŶŐ
ƵƚŚŽƌŝƚLJƐŚĂůůƌĞƚƵƌŶ

ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJŽƌZĞƐĞƌǀĞ
^ŚĂƌŝŶŐ'ƌŽƵƉƐŚĂůůŵĞĞƚƚŚĞ
ŝƐƚƵƌďĂŶĐĞZĞĐŽǀĞƌLJƌŝƚĞƌŝŽŶ
ǁŝƚŚŝŶƚŚĞŝƐƚƵƌďĂŶĐĞZĞĐŽǀĞƌLJ
WĞƌŝŽĚĨŽƌϭϬϬйŽĨZĞƉŽƌƚĂďůĞ
ŝƐƚƵƌďĂŶĐĞƐ͘dŚĞŝƐƚƵƌďĂŶĐĞ
ZĞĐŽǀĞƌLJƌŝƚĞƌŝŽŶŝƐ͗
•

&ƵƌƚŚĞƌƌĞĚƵĐĞĚďLJƚŚĞŵĂŐŶŝƚƵĚĞŽĨƚŚĞ
ĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶ;ŝͿƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛Ɛ
o

ϴ 

ůĞƐƐƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨĂůů
ƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚ
ŽĐĐƵƌƉƌŝŽƌƚŽƚŚĂƚǀĂůƵĞŽĨZĞƉŽƌƚŝŶŐ
ǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕
ĂŶĚ
o

ĞƌŽ͕;ŝĨŝƚƐWƌĞͲZĞƉŽƌƚŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
sĂůƵĞǁĂƐƉŽƐŝƚŝǀĞŽƌĞƋƵĂůƚŽnjĞƌŽͿ͗

dŚŝƐZĞƋƵŝƌĞŵĞŶƚŚĂƐďĞĞŶ
>ͲϬϬϮͲϬZĞƋƵŝƌĞŵĞŶƚZϰĂŶĚZϰ͘ϭƚŽ>ͲϬϬϮͲϮ
ŵŽǀĞĚŝŶƚŽ>ͲϬϬϮͲϮ
ZĞƋƵŝƌĞŵĞŶƚZϭ
ZĞƋƵŝƌĞŵĞŶƚZϭĂŶĚŝŶƚŽƚŚĞ
ϭ͘ dŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJĞdžƉĞƌŝĞŶĐŝŶŐĂZĞƉŽƌƚĂďůĞ
͞ŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐŚĂůů͕ǁŝƚŚŝŶƚŚĞ
WĞƌŝŽĚ͟ĂŶĚ͞ŽŶƚŝŶŐĞŶĐLJ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕ƌĞƚƵƌŶŝƚƐƚŽĂƚ
ZĞƐĞƌǀĞZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚ͟
ůĞĂƐƚ͗΀sŝŽůĂƚŝŽŶZŝƐŬ&ĂĐƚŽƌ͗DĞĚŝƵŵ΁΀dŝŵĞ,ŽƌŝnjŽŶ͗
ĚĞĨŝŶŝƚŝŽŶƐ͘
ZĞĂůͲƚŝŵĞKƉĞƌĂƚŝŽŶƐ΁



and Contingency Reserve Restoration Period, or during
an Energy Emergency Alert Level 2 or Level 3, each
Responsible Entity shall maintain an amount of
Contingency Reserve at least equal to its Most Severe
Single Contingency.

>ͲϬϬϮͲϮŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ


Zϰ͘

^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϬ
EZŽĂƌĚƉƉƌŽǀĞĚ

>ͲϬϬϮͲϬDĂƉƉŝŶŐƚŽWƌŽƉŽƐĞĚEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ
ŽŵŵĞŶƚ
WƌŽƉŽƐĞĚ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ



•

DŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;D^^ͿĂŶĚ;ŝŝͿ
ƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨƚŚĞZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚĂůůƉƌĞǀŝŽƵƐ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚŚĂǀĞŶŽƚ
ĐŽŵƉůĞƚĞĚƚŚĞŝƌŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ
ZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚǁŚĞŶƚŚĞƐƵŵƌĞĨĞƌĞŶĐĞĚŝŶ
ĐůĂƵƐĞ;ŝŝͿŽĨƚŚŝƐďƵůůĞƚŝƐŐƌĞĂƚĞƌƚŚĂŶD^^͕

ϵ 

o &ƵƌƚŚĞƌƌĞĚƵĐĞĚďLJƚŚĞŵĂŐŶŝƚƵĚĞŽĨƚŚĞ
ĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶ;ŝͿƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛Ɛ
DŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;D^^ͿĂŶĚ;ŝŝͿ
ƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨƚŚĞZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚĂůůƉƌĞǀŝŽƵƐ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚŚĂǀĞŶŽƚ
ĐŽŵƉůĞƚĞĚƚŚĞŝƌŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ

o ůĞƐƐƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨĂůů
ƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚ
ŽĐĐƵƌƉƌŝŽƌƚŽƚŚĂƚǀĂůƵĞŽĨZĞƉŽƌƚŝŶŐ
ǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕
ĂŶĚ

/ƚƐWƌĞͲZĞƉŽƌƚŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞ͕;ŝĨ
ŝƚƐWƌĞͲZĞƉŽƌƚŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞǁĂƐ
ŶĞŐĂƚŝǀĞͿ͕

Kƌ͕

>ͲϬϬϮͲϮŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ


Zϰ͘Ϯ͘dŚĞĚĞĨĂƵůƚŝƐƚƵƌďĂŶĐĞ
ZĞĐŽǀĞƌLJWĞƌŝŽĚŝƐϭϱ
ŵŝŶƵƚĞƐĂĨƚĞƌƚŚĞƐƚĂƌƚŽĨĂ
ZĞƉŽƌƚĂďůĞŝƐƚƵƌďĂŶĐĞ͘
ĂĐŚĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ
ƐŚĂůůŚĂǀĞĂĐĐĞƐƐƚŽĂŶĚͬŽƌ
ŽƉĞƌĂƚĞŽŶƚŝŶŐĞŶĐLJ
ZĞƐĞƌǀĞƚŽƌĞƐƉŽŶĚƚŽ
ŝƐƚƵƌďĂŶĐĞƐ͘ŽŶƚŝŶŐĞŶĐLJ
ZĞƐĞƌǀĞŵĂLJďĞƐƵƉƉůŝĞĚ
ĨƌŽŵŐĞŶĞƌĂƚŝŽŶ͕
ĐŽŶƚƌŽůůĂďůĞůŽĂĚƌĞƐŽƵƌĐĞƐ͕
ŽƌĐŽŽƌĚŝŶĂƚĞĚĂĚũƵƐƚŵĞŶƚƐ
ƚŽ/ŶƚĞƌĐŚĂŶŐĞ^ĐŚĞĚƵůĞƐ͘

^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϬ
EZŽĂƌĚƉƉƌŽǀĞĚ
ƚŽŝƚƐƉƌĞͲŝƐƚƵƌďĂŶĐĞǀĂůƵĞ͘

>ͲϬϬϮͲϬDĂƉƉŝŶŐƚŽWƌŽƉŽƐĞĚEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ
ŽŵŵĞŶƚ
WƌŽƉŽƐĞĚ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ

ZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚǁŚĞŶƚŚĞƐƵŵƌĞĨĞƌĞŶĐĞĚŝŶ
ĐůĂƵƐĞ;ŝŝͿŽĨƚŚŝƐďƵůůĞƚŝƐŐƌĞĂƚĞƌƚŚĂŶD^^͘

ϭϬ

KĨƵƌƚŚĞƌƌĞĚƵĐĞĚďLJƚŚĞŵĂŐŶŝƚƵĚĞŽĨƚŚĞ
ĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶ;ŝͿƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛Ɛ
DŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;D^^ͿĂŶĚ;ŝŝͿƚŚĞ
ƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨƚŚĞZĞƉŽƌƚĂďůĞ

KůĞƐƐƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨĂůůƐƵďƐĞƋƵĞŶƚ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚŽĐĐƵƌǁŝƚŚŝŶƚŚĞ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕ĂŶĚ

ͻĞƌŽ͕;ŝĨŝƚƐWƌĞͲZĞƉŽƌƚĂďůĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
sĂůƵĞǁĂƐƉŽƐŝƚŝǀĞŽƌĞƋƵĂůƚŽnjĞƌŽͿ͗

ϭ͘ džĐĞƉƚǁŚĞŶĂŶŶĞƌŐLJŵĞƌŐĞŶĐLJůĞƌƚ>ĞǀĞůϮŽƌϯŝƐŝŶ
ĞĨĨĞĐƚ͕ƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJĞdžƉĞƌŝĞŶĐŝŶŐĂZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐŚĂůůĚĞŵŽŶƐƚƌĂƚĞƚŚĂƚ
ǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚƚŚĞ
ZĞƐƉŽŶƐŝďůĞŶƚŝƚLJƌĞƚƵƌŶĞĚŝƚƐƚŽ͗

ϭ͘Ϯ͘ dŚŝƐƌĞƋƵŝƌĞŵĞŶƚ;ŝŶŝƚƐĞŶƚŝƌĞƚLJͿĚŽĞƐŶŽƚĂƉƉůLJ
ǁŚĞŶƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJĞdžƉĞƌŝĞŶĐŝŶŐĂ
ZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚŝƐ
ĞdžƉĞƌŝĞŶĐŝŶŐĂŶŶĞƌŐLJŵĞƌŐĞŶĐLJůĞƌƚ>ĞǀĞůϮŽƌ
>ĞǀĞůϯ͘

ϭ͘ϭ͘dŚĞƌĞƋƵŝƌĞĚƌĞƉŽƌƚŝŶŐĨŽƌŵŝƐZ&Žƌŵϭ͘

>ͲϬϬϮͲϮŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ


^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϬ
EZŽĂƌĚƉƉƌŽǀĞĚ

>ͲϬϬϮͲϬDĂƉƉŝŶŐƚŽWƌŽƉŽƐĞĚEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ
ŽŵŵĞŶƚ
WƌŽƉŽƐĞĚ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ





ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚĂůůƉƌĞǀŝŽƵƐ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚŚĂǀĞŶŽƚ
ĐŽŵƉůĞƚĞĚƚŚĞŝƌŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞƐƚŽƌĂƚŝŽŶ
WĞƌŝŽĚǁŚĞŶƚŚĞƐƵŵƌĞĨĞƌĞŶĐĞĚŝŶĐůĂƵƐĞ;ŝŝͿŽĨ
ƚŚŝƐďƵůůĞƚŝƐŐƌĞĂƚĞƌƚŚĂŶD^^͕

ϭϭ

K&ƵƌƚŚĞƌƌĞĚƵĐĞĚďLJƚŚĞŵĂŐŶŝƚƵĚĞŽĨƚŚĞ
ĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶ;ŝͿƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛Ɛ
DŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;D^^ͿĂŶĚ;ŝŝͿƚŚĞ
ƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨƚŚĞZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚĂůůƉƌĞǀŝŽƵƐ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚŚĂǀĞŶŽƚ
ĐŽŵƉůĞƚĞĚƚŚĞŝƌŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞƐƚŽƌĂƚŝŽŶ
WĞƌŝŽĚǁŚĞŶƚŚĞƐƵŵƌĞĨĞƌĞŶĐĞĚŝŶĐůĂƵƐĞ;ŝŝͿŽĨ
ƚŚŝƐďƵůůĞƚŝƐŐƌĞĂƚĞƌƚŚĂŶD^^͘

K>ĞƐƐƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞŽĨĂůůƐƵďƐĞƋƵĞŶƚ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚŽĐĐƵƌǁŝƚŚŝŶƚŚĞ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕ĂŶĚ

ͻ/ƚƐWƌĞͲZĞƉŽƌƚĂďůĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞ͕;ŝĨŝƚƐ
WƌĞͲZĞƉŽƌƚĂďůĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞǁĂƐ
ŶĞŐĂƚŝǀĞͿ͗

Kƌ͕

>ͲϬϬϮͲϮŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ


^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϬ
EZŽĂƌĚƉƉƌŽǀĞĚ

>ͲϬϬϮͲϬDĂƉƉŝŶŐƚŽWƌŽƉŽƐĞĚEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ
ŽŵŵĞŶƚ
WƌŽƉŽƐĞĚ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ



•

o

ϭϮ

ůĞƐƐƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨĂůů
ƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚ
ŽĐĐƵƌƉƌŝŽƌƚŽƚŚĂƚǀĂůƵĞŽĨZĞƉŽƌƚŝŶŐ

ĞƌŽ͕;ŝĨŝƚƐWƌĞͲZĞƉŽƌƚŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
sĂůƵĞǁĂƐƉŽƐŝƚŝǀĞŽƌĞƋƵĂůƚŽnjĞƌŽͿ͗

ϭ͘ dŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJĞdžƉĞƌŝĞŶĐŝŶŐĂZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐŚĂůů͕ǁŝƚŚŝŶƚŚĞ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕ƌĞƚƵƌŶŝƚƐƚŽĂƚ
ůĞĂƐƚ͗΀sŝŽůĂƚŝŽŶZŝƐŬ&ĂĐƚŽƌ͗DĞĚŝƵŵ΁΀dŝŵĞ,ŽƌŝnjŽŶ͗
ZĞĂůͲƚŝŵĞKƉĞƌĂƚŝŽŶƐ΁

ZĞƋƵŝƌĞŵĞŶƚZϭ

>ͲϬϬϮͲϮ

ƉĞƌŝŽĚŶŽƚĞdžĐĞĞĚŝŶŐϵϬŵŝŶƵƚĞƐĨŽůůŽǁŝŶŐƚŚĞĞŶĚŽĨ
ƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͘

ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚ͗

ƉĞƌŝŽĚďĞŐŝŶŶŝŶŐĂƚƚŚĞƚŝŵĞƚŚĂƚƚŚĞƌĞƐŽƵƌĐĞ
ŽƵƚƉƵƚďĞŐŝŶƐƚŽĚĞĐůŝŶĞǁŝƚŚŝŶƚŚĞĨŝƌƐƚŽŶĞͲ
ŵŝŶƵƚĞŝŶƚĞƌǀĂůƚŚĂƚĚĞĨŝŶĞƐĂĂůĂŶĐŝŶŐ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ͕ĂŶĚĞdžƚĞŶĚƐĨŽƌĨŝĨƚĞĞŶŵŝŶƵƚĞƐ
ƚŚĞƌĞĂĨƚĞƌ͘

ŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ

>ͲϬϬϮͲϮŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ


Zϱ͘ ĂĐŚZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉƐŚĂůů dŚŝƐZĞƋƵŝƌĞŵĞŶƚŚĂƐďĞĞŶ
ĐŽŵƉůLJǁŝƚŚƚŚĞ^͘ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ
ŵŽǀĞĚŝŶƚŽ>ͲϬϬϮͲϮ
'ƌŽƵƉƐŚĂůůďĞĐŽŶƐŝĚĞƌĞĚŝŶĂ
ZĞƋƵŝƌĞŵĞŶƚZϭĂŶĚ
ZĞƉŽƌƚĂďůĞŝƐƚƵƌďĂŶĐĞĐŽŶĚŝƚŝŽŶ
ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ
ǁŚĞŶĞǀĞƌĂŐƌŽƵƉŵĞŵďĞƌŚĂƐ
ZĞƉŽƌƚŝŶŐ
ĞdžƉĞƌŝĞŶĐĞĚĂZĞƉŽƌƚĂďůĞŝƐƚƵƌďĂŶĐĞ
ĂŶĚĐĂůůƐĨŽƌƚŚĞĂĐƚŝǀĂƚŝŽŶŽĨ
ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞƐĨƌŽŵŽŶĞŽƌŵŽƌĞ
ŽƚŚĞƌŐƌŽƵƉŵĞŵďĞƌƐ͘;/ĨĂŐƌŽƵƉ
ŵĞŵďĞƌŚĂƐĞdžƉĞƌŝĞŶĐĞĚĂZĞƉŽƌƚĂďůĞ
ŝƐƚƵƌďĂŶĐĞďƵƚĚŽĞƐŶŽƚĐĂůůĨŽƌƌĞƐĞƌǀĞ
ĂĐƚŝǀĂƚŝŽŶĨƌŽŵŽƚŚĞƌŵĞŵďĞƌƐŽĨƚŚĞ
ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ͕ƚŚĞŶƚŚĂƚ
ŵĞŵďĞƌƐŚĂůůƌĞƉŽƌƚĂƐĂƐŝŶŐůĞ

^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϬ
EZŽĂƌĚƉƉƌŽǀĞĚ

>ͲϬϬϮͲϬDĂƉƉŝŶŐƚŽWƌŽƉŽƐĞĚEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ
ŽŵŵĞŶƚ
WƌŽƉŽƐĞĚ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ



•

o

&ƵƌƚŚĞƌƌĞĚƵĐĞĚďLJƚŚĞŵĂŐŶŝƚƵĚĞŽĨƚŚĞ
ĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶ;ŝͿƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛Ɛ
DŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;D^^ͿĂŶĚ;ŝŝͿ
ƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨƚŚĞZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚĂůůƉƌĞǀŝŽƵƐ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚŚĂǀĞŶŽƚ
ĐŽŵƉůĞƚĞĚƚŚĞŝƌŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ
ZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚǁŚĞŶƚŚĞƐƵŵƌĞĨĞƌĞŶĐĞĚŝŶ
ĐůĂƵƐĞ;ŝŝͿŽĨƚŚŝƐďƵůůĞƚŝƐŐƌĞĂƚĞƌƚŚĂŶD^^͕

ǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕
ĂŶĚ

ϭϯ

o &ƵƌƚŚĞƌƌĞĚƵĐĞĚďLJƚŚĞŵĂŐŶŝƚƵĚĞŽĨƚŚĞ
ĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶ;ŝͿƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛Ɛ
DŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;D^^ͿĂŶĚ;ŝŝͿ

o ůĞƐƐƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨĂůů
ƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚ
ŽĐĐƵƌƉƌŝŽƌƚŽƚŚĂƚǀĂůƵĞŽĨZĞƉŽƌƚŝŶŐ
ǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕
ĂŶĚ

/ƚƐWƌĞͲZĞƉŽƌƚŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞ͕;ŝĨ
ŝƚƐWƌĞͲZĞƉŽƌƚŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞǁĂƐ
ŶĞŐĂƚŝǀĞͿ͕

Kƌ͕

>ͲϬϬϮͲϮŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ


^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϬ
EZŽĂƌĚƉƉƌŽǀĞĚ
ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͘ͿŽŵƉůŝĂŶĐĞŵĂLJ
ďĞĚĞŵŽŶƐƚƌĂƚĞĚďLJĞŝƚŚĞƌŽĨƚŚĞ
ĨŽůůŽǁŝŶŐƚǁŽŵĞƚŚŽĚƐ͗

Zϱ͘ϭ͘dŚĞZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ
ƌĞǀŝĞǁƐŐƌŽƵƉ;Žƌ
ĞƋƵŝǀĂůĞŶƚͿĂŶĚĚĞŵŽŶƐƚƌĂƚĞƐ
ĐŽŵƉůŝĂŶĐĞƚŽƚŚĞ^͘dŽďĞŝŶ
ĐŽŵƉůŝĂŶĐĞ͕ƚŚĞŐƌŽƵƉ;ŽƌŝƚƐ
ĞƋƵŝǀĂůĞŶƚͿŵƵƐƚŵĞĞƚƚŚĞ
ŝƐƚƵƌďĂŶĐĞZĞĐŽǀĞƌLJƌŝƚĞƌŝŽŶ
ĂĨƚĞƌƚŚĞƐĐŚĞĚƵůĞĐŚĂŶŐĞ;ƐͿ
ƌĞůĂƚĞĚƚŽƌĞƐĞƌǀĞƐŚĂƌŝŶŐŚĂǀĞ
ďĞĞŶĨƵůůLJŝŵƉůĞŵĞŶƚĞĚ͕ĂŶĚ
ǁŝƚŚŝŶƚŚĞŝƐƚƵƌďĂŶĐĞZĞĐŽǀĞƌLJ
WĞƌŝŽĚ͘

Žƌ

Zϱ͘Ϯ͘dŚĞZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ
ƌĞǀŝĞǁƐĞĂĐŚŵĞŵďĞƌ͛ƐŝŶ
ƌĞƐƉŽŶƐĞƚŽƚŚĞĂĐƚŝǀĂƚŝŽŶŽĨ
ƌĞƐĞƌǀĞƐ͘dŽďĞŝŶĐŽŵƉůŝĂŶĐĞ͕Ă
ŵĞŵďĞƌ͛Ɛ;ŽƌŝƚƐĞƋƵŝǀĂůĞŶƚͿ
ŵƵƐƚŵĞĞƚƚŚĞŝƐƚƵƌďĂŶĐĞ

>ͲϬϬϮͲϬDĂƉƉŝŶŐƚŽWƌŽƉŽƐĞĚEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ
ŽŵŵĞŶƚ
WƌŽƉŽƐĞĚ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ



ƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨƚŚĞZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚĂůůƉƌĞǀŝŽƵƐ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚŚĂǀĞŶŽƚ
ĐŽŵƉůĞƚĞĚƚŚĞŝƌŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ
ZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚǁŚĞŶƚŚĞƐƵŵƌĞĨĞƌĞŶĐĞĚŝŶ
ĐůĂƵƐĞ;ŝŝͿŽĨƚŚŝƐďƵůůĞƚŝƐŐƌĞĂƚĞƌƚŚĂŶD^^͘

•

o

ϭϰ

ůĞƐƐƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨĂůů
ƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚ
ŽĐĐƵƌǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJ

ĞƌŽ͕;ŝĨŝƚƐWƌĞͲZĞƉŽƌƚĂďůĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
sĂůƵĞǁĂƐƉŽƐŝƚŝǀĞŽƌĞƋƵĂůƚŽnjĞƌŽͿ͗

Ϯ͘ džĐĞƉƚǁŚĞŶĂŶŶĞƌŐLJŵĞƌŐĞŶĐLJůĞƌƚ>ĞǀĞůϮŽƌϯŝƐŝŶ
ĞĨĨĞĐƚ͕ƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJĞdžƉĞƌŝĞŶĐŝŶŐĂZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐŚĂůůĚĞŵŽŶƐƚƌĂƚĞƚŚĂƚ
ǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚƚŚĞ
ZĞƐƉŽŶƐŝďůĞŶƚŝƚLJƌĞƚƵƌŶĞĚŝƚƐƚŽ͗

ϭ͘Ϯ͘ dŚŝƐƌĞƋƵŝƌĞŵĞŶƚ;ŝŶŝƚƐĞŶƚŝƌĞƚLJͿĚŽĞƐŶŽƚĂƉƉůLJ
ǁŚĞŶƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJĞdžƉĞƌŝĞŶĐŝŶŐĂ
ZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚŝƐ
ĞdžƉĞƌŝĞŶĐŝŶŐĂŶŶĞƌŐLJŵĞƌŐĞŶĐLJůĞƌƚ>ĞǀĞůϮŽƌ
>ĞǀĞůϯ͘

ϭ͘ϭ͘dŚĞƌĞƋƵŝƌĞĚƌĞƉŽƌƚŝŶŐĨŽƌŵŝƐZ&Žƌŵϭ͘

>ͲϬϬϮͲϮŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ


^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϬ
EZŽĂƌĚƉƉƌŽǀĞĚ
ZĞĐŽǀĞƌLJƌŝƚĞƌŝŽŶĂĨƚĞƌƚŚĞ
ƐĐŚĞĚƵůĞĐŚĂŶŐĞ;ƐͿƌĞůĂƚĞĚƚŽ
ƌĞƐĞƌǀĞƐŚĂƌŝŶŐŚĂǀĞďĞĞŶĨƵůůLJ
ŝŵƉůĞŵĞŶƚĞĚ͕ĂŶĚǁŝƚŚŝŶƚŚĞ
ŝƐƚƵƌďĂŶĐĞZĞĐŽǀĞƌLJWĞƌŝŽĚ͘

>ͲϬϬϮͲϬDĂƉƉŝŶŐƚŽWƌŽƉŽƐĞĚEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ
ŽŵŵĞŶƚ
WƌŽƉŽƐĞĚ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ



•

Kƌ͕

o

ĨƵƌƚŚĞƌƌĞĚƵĐĞĚďLJƚŚĞŵĂŐŶŝƚƵĚĞŽĨƚŚĞ
ĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶ;ŝͿƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛Ɛ
DŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;D^^ͿĂŶĚ;ŝŝͿ
ƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨƚŚĞZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚĂůůƉƌĞǀŝŽƵƐ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚŚĂǀĞŶŽƚ
ĐŽŵƉůĞƚĞĚƚŚĞŝƌŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞƐƚŽƌĂƚŝŽŶ
WĞƌŝŽĚǁŚĞŶƚŚĞƐƵŵƌĞĨĞƌĞŶĐĞĚŝŶĐůĂƵƐĞ;ŝŝͿ
ŽĨƚŚŝƐďƵůůĞƚŝƐŐƌĞĂƚĞƌƚŚĂŶD^^͕

WĞƌŝŽĚ͕ĂŶĚ

ϭϱ

o &ƵƌƚŚĞƌƌĞĚƵĐĞĚďLJƚŚĞŵĂŐŶŝƚƵĚĞŽĨƚŚĞ
ĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶ;ŝͿƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛Ɛ
DŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;D^^ͿĂŶĚ
;ŝŝͿƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨƚŚĞ
ZĞƉŽƌƚĂďůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚ

o >ĞƐƐƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞŽĨĂůů
ƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚ
ŽĐĐƵƌǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJ
WĞƌŝŽĚ͕ĂŶĚ

/ƚƐWƌĞͲZĞƉŽƌƚĂďůĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞ͕;ŝĨ
ŝƚƐWƌĞͲZĞƉŽƌƚĂďůĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞǁĂƐ
ŶĞŐĂƚŝǀĞͿ͗

>ͲϬϬϮͲϮŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ


^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϬ
EZŽĂƌĚƉƉƌŽǀĞĚ

>ͲϬϬϮͲϬDĂƉƉŝŶŐƚŽWƌŽƉŽƐĞĚEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ
ŽŵŵĞŶƚ
WƌŽƉŽƐĞĚ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ





Zϲ͘ϭ͘dŚĞŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ
ZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚďĞŐŝŶƐĂƚ

ĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJŽƌZĞƐĞƌǀĞ
^ŚĂƌŝŶŐ'ƌŽƵƉƐŚĂůůĨƵůůLJƌĞƐƚŽƌĞ
ŝƚƐŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞƐǁŝƚŚŝŶ
ƚŚĞŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ
ZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚĨŽƌŝƚƐ
/ŶƚĞƌĐŽŶŶĞĐƚŝŽŶ͘

•

ĞƌŽ͕;ŝĨŝƚƐWƌĞͲZĞƉŽƌƚŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ

ϭϲ

dŚŝƐZĞƋƵŝƌĞŵĞŶƚŚĂƐďĞĞŶ
>ͲϬϬϮͲϮ
ŵŽǀĞĚŝŶƚŽƚŚĞ>ͲϬϬϮͲϮ

ZĞƋƵŝƌĞŵĞŶƚZϭĂŶĚ
ZĞƋƵŝƌĞŵĞŶƚZϭ
͞ŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
ZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚ͟ĚĞĨŝŶŝƚŝŽŶ
ϭ͘ dŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJĞdžƉĞƌŝĞŶĐŝŶŐĂZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐŚĂůů͕ǁŝƚŚŝŶƚŚĞ
ŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕ƌĞƚƵƌŶŝƚƐƚŽĂƚ
ůĞĂƐƚ͗΀sŝŽůĂƚŝŽŶZŝƐŬ&ĂĐƚŽƌ͗DĞĚŝƵŵ΁΀dŝŵĞ,ŽƌŝnjŽŶ͗
ZĞĂůͲƚŝŵĞKƉĞƌĂƚŝŽŶƐ΁



ĂůůƉƌĞǀŝŽƵƐĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚ
ŚĂǀĞŶŽƚĐŽŵƉůĞƚĞĚƚŚĞŝƌŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
ZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚǁŚĞŶƚŚĞƐƵŵƌĞĨĞƌĞŶĐĞĚ
ŝŶĐůĂƵƐĞ;ŝŝͿŽĨƚŚŝƐďƵůůĞƚŝƐŐƌĞĂƚĞƌƚŚĂŶ
D^^͘
ZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉZĞƉŽƌƚŝŶŐ
ƚĂŶLJŐŝǀĞŶƚŝŵĞŽĨŵĞĂƐƵƌĞŵĞŶƚĨŽƌƚŚĞ
ĂƉƉůŝĐĂďůĞZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ͕ƚŚĞĂůŐĞďƌĂŝĐ
ƐƵŵŽĨƚŚĞƐ;ĂƐĐĂůĐƵůĂƚĞĚĂƚƐƵĐŚƚŝŵĞŽĨ
ŵĞĂƐƵƌĞŵĞŶƚͿŽĨĂůůŽĨƚŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚŝĞƐ
ƚŚĂƚŵĂŬĞƵƉƚŚĞZĞƐĞƌǀĞ^ŚĂƌŝŶŐ'ƌŽƵƉ͘



>ͲϬϬϮͲϮŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ


Zϲ͘

^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϬ
EZŽĂƌĚƉƉƌŽǀĞĚ

>ͲϬϬϮͲϬDĂƉƉŝŶŐƚŽWƌŽƉŽƐĞĚEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ
ŽŵŵĞŶƚ
WƌŽƉŽƐĞĚ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ





•

&ƵƌƚŚĞƌƌĞĚƵĐĞĚďLJƚŚĞŵĂŐŶŝƚƵĚĞŽĨƚŚĞ
ĚŝĨĨĞƌĞŶĐĞďĞƚǁĞĞŶ;ŝͿƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJ͛Ɛ
DŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ;D^^ͿĂŶĚ;ŝŝͿ
ƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨƚŚĞZĞƉŽƌƚĂďůĞ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚĂŶĚĂůůƉƌĞǀŝŽƵƐ
ĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚŚĂǀĞŶŽƚ
ĐŽŵƉůĞƚĞĚƚŚĞŝƌŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ
ZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚǁŚĞŶƚŚĞƐƵŵƌĞĨĞƌĞŶĐĞĚŝŶ
ĐůĂƵƐĞ;ŝŝͿŽĨƚŚŝƐďƵůůĞƚŝƐŐƌĞĂƚĞƌƚŚĂŶD^^͕
o

ϭϳ

o ůĞƐƐƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨĂůů
ƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚ
ŽĐĐƵƌƉƌŝŽƌƚŽƚŚĂƚǀĂůƵĞŽĨZĞƉŽƌƚŝŶŐ
ǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕

/ƚƐWƌĞͲZĞƉŽƌƚŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞ͕;ŝĨ
ŝƚƐWƌĞͲZĞƉŽƌƚŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚsĂůƵĞǁĂƐ
ŶĞŐĂƚŝǀĞͿ͕

Kƌ͕

ůĞƐƐƚŚĞƐƵŵŽĨƚŚĞŵĂŐŶŝƚƵĚĞƐŽĨĂůů
ƐƵďƐĞƋƵĞŶƚĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐƚŚĂƚ
ŽĐĐƵƌƉƌŝŽƌƚŽƚŚĂƚǀĂůƵĞŽĨZĞƉŽƌƚŝŶŐ
ǁŝƚŚŝŶƚŚĞŽŶƚŝŶŐĞŶĐLJǀĞŶƚZĞĐŽǀĞƌLJWĞƌŝŽĚ͕
ĂŶĚ

o

sĂůƵĞǁĂƐƉŽƐŝƚŝǀĞŽƌĞƋƵĂůƚŽnjĞƌŽͿ͗

>ͲϬϬϮͲϮŝƐƚƵƌďĂŶĐĞŽŶƚƌŽůWĞƌĨŽƌŵĂŶĐĞͲŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĨŽƌZĞĐŽǀĞƌLJĨƌŽŵĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚ
:ƵůLJϮϬϭϯ


Zϲ͘Ϯ͘dŚĞĚĞĨĂƵůƚŽŶƚŝŶŐĞŶĐLJ
ZĞƐĞƌǀĞZĞƐƚŽƌĂƚŝŽŶWĞƌŝŽĚ
ŝƐϵϬŵŝŶƵƚĞƐ͘

^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϬ
EZŽĂƌĚƉƉƌŽǀĞĚ
ƚŚĞĞŶĚŽĨƚŚĞŝƐƚƵƌďĂŶĐĞ
ZĞĐŽǀĞƌLJWĞƌŝŽĚ͘

>ͲϬϬϮͲϬDĂƉƉŝŶŐƚŽWƌŽƉŽƐĞĚEZZĞůŝĂďŝůŝƚLJ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ
ŽŵŵĞŶƚ
WƌŽƉŽƐĞĚ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ



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ŽŵŵĞŶƚ
WƌŽƉŽƐĞĚ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ



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ĨƵƌƚŚĞƌƌĞĚƵĐĞĚďLJƚŚĞŵĂŐŶŝƚƵĚĞŽĨƚŚĞ
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^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϬ
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ŽŵŵĞŶƚ
WƌŽƉŽƐĞĚ^ƚĂŶĚĂƌĚ>ͲϬϬϮͲϮ



Standards Announcement
Project 2010-14.1 Balancing Authority Reliability-based
Controls: Reserves
BAL-002-2
Formal Comment Period: August 2, 2013 – September 16, 2013
Upcoming:
Additional Ballot and Non-Binding Poll: September 6-16, 2013
Now Available

A 45-day formal comment period for BAL-002-2- Contingency Reserve for Recovery from a
Balancing Contingency Event is now open through 8 p.m. Eastern on Monday, September 16,
2013.
Background information for this project can be found on the project page.
Instructions for Commenting

A formal comment period is open through 8 p.m. Eastern on Monday, September 16, 2013. Please
use the electronic comment form to submit comments. If you experience any difficulties in using the
electronic form, please contact Wendy Muller. An off-line, unofficial copy of the comment form is
posted on the project page.
Next Steps

A ballot for the standard and a non-binding poll of the associated Violation Risk Factors (VRFs) and
Violation Severity Levels (VSLs) will be conducted as previously outlined.
Standards Development Process

The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.

For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.

North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Announcement – Project 2010-14.1 BAL-002-2

2

Individual or group. (34 Responses)
Name (18 Responses)
Organization (18 Responses)
Group Name (16 Responses)
Lead Contact (16 Responses)
IF YOU WISH TO EXPRESS SUPPORT FOR ANOTHER ENTITY'S COMMENTS WITHOUT ENTERING ANY
ADDITIONAL COMMENTS, YOU MAY DO SO HERE. (10 Responses)
Comments (34 Responses)
Question 1 (0 Responses)
Question 1 Comments (24 Responses)

Group
Northeast Power Coordinating Council
Guy Zito
There are concerns with the changes proposed to BAL-002 that were made without demonstrated need, and not proposed
in the SAR nor directed in Order No. 693. The NERC Resources Subcommittee performed analysis when DCS was
developed and found that the average time to recover from large unit trips was 15 minutes. Recent analysis for BAL-003
has found that all four Interconnections recover from large unit trips in about 5 minutes. Performance in recent years has
been noticeably improved. This Standard should not be used to define terms not directly needed in the Standard (e.g.
Reporting ACE). We disagree with the new definition of Contingency Reserve as it provides no guidance on how to
objectively measure reserves. Regarding R1, there is no reasoning provided for the complexity added to the calculation.
The current approach is well understood in the industry. The SAR does not discuss changing the measurement approach.
In particular, DCS performance has always be calculated and reported on a quarterly basis. There have been no reliability
issues that point to the need for making the DCS an event-by-event standard as is now proposed. The original Policy 1
noted many reasons for operating reserves. BAs whose ACE is extremely negative for other reasons would be reluctant to
deploy their contingency reserves because the timer would start ticking on the “available hours” clock. The second
unintended consequence for those BAs that don’t withhold contingency reserves for non-DCS events is that they will be
obliged to increase the amount of contingencies they cover so they always have more reserves than their MSSC. This will
increase costs to customers without a demonstrated need. DCS performance in North America has been stellar compared
to what was considered adequate performance under Policy 1. The Standard provides no clear definition on how
contingency reserves are measured. Does it include all generation headroom available in 10 minutes? In 15 minutes?
What about resources that are also providing AGC? Does their instantaneous headroom count? Are load resources
available in 10 or 15 minutes? What about demand response resources that aren’t directly measured? Finally, are the
hours referenced in the Standard clock hours, any contiguous 60 minute periods, or the total minutes in a quarter divided
by 60? The SAR directed cleaning up the V0 clutter in the Standard and address Order No. 693 directives. The only two
true requirements in the V0 standard are to recover from reportable events in 15 minutes and replenish reserves 90
minutes thereafter. These should be the basis of this standard. We recommend the two core requirements be: R1. Except
when experiencing an Energy Emergency Alert Level 2 or Level 3, a Balancing Authority or Reserve Sharing Group
experiencing a Reportable Event less than or equal to its MSSC shall activate sufficient Contingency Reserve to comply
with the DCS. R2. Except when experiencing an Energy Emergency Alert Level 2 or Level 3, a Balancing Authority or
Reserve Sharing Group experiencing a Reportable Event less than or equal to its MSSC shall replenish its reserves within
105 minutes of the onset of the Reportable Event. The sizes of the Reportable Events for the Interconnections are
acceptable. The reporting form should be similar to what is used today. The form should include the basis of the MSSC
and the date of the last review of MSSC. We believe it is acceptable to put something in the Compliance Section of the
Standard that notes if the same event greater than MSSC occurs within 3 years, the BA should be held to the DCS for that
contingency. We agree with the current direction of the Drafting Team to address the directive for the “continent-wide
contingency reserve policy” is via the “Reserve Guidelines” document being developed. The document should provide
guidance on how the BA assesses the necessary amount of reserves as well as provide simple definitions of the different
types of reserves. Once these terms are defined and commented on by the Industry in the document, NERC should add
these types of reserves to “Attachment 1-TOP-005 Electric System Reliability Data” with the expectation in the policy that
Reliability Coordinators collect this information in real time for use in the EEA process. The policy could ask the BAs to
initially review and assess their needs and report this to their RC. This would directly contribute to reliability by providing
objective information to BAs and RCs in managing Energy Emergency Alerts. The format of the Requirements must be
made to conform to NERC standards development rules, and a timeline should be provided for showing what is needed to
have adequate contingency reserves. We also disagree with the new definition of Pre-Reporting Contingency Event ACE
Value. The 16 second averaging requirement adds complexity to the calculation with no justification.
Group
Arizona Public Service Company
Janet Smith, Regulatory Affairs Supervisor
• AZPS Comments: The wording of the qualifying contingency events that affect the disturbance ACE recovery value in R1
is hard to understand. • AZPS Proposed solution: offer an example(s) of overlapping contingency events and how they
affect the target ACE recovery value.
Individual
Nazra Gladu

Manitoba Hydro
Manitoba Hydro is in support of this revised standard.
Group
Salt River Project
Bob Steiger
The draft standard introduces several magnitudes of complexity when compared with the existing standard. We
understand and appreciate the reasoning behind accommodating preceding and subsequent contingency events in a
measured recovery. However, our BA could not grasp the concept of how compliance would be determined until they
downloaded and used the “CR Form 1” spreadsheet. This was the only way they could comprehend how the preceding and
subsequent events would be calculated into final compliance determination. The wording of a requirement should be clear
and stand-alone. We favor the definition of the Reporting ACE and the designation of the ATEC ACE for the WECC. We are
concerned that the complexity will ultimately result in many NO votes simply because of the difficulty to understand the
compliance concept. I suggest the DT simplify the requirement language.
Group
Tennessee Valley Authority
Dennis Chastain
Agree
SERC OC Review Group
Individual
John Bee
Exelon and its' affiliates
While we appreciate the work done since previous versions of the project, and recognize the clarity gained by eliminating
reference to Balancing Contingency Events with a future impact to ACE, we feel that additional confusion has been
inserted by the sub-points of R1. Given that the recovery requirement is a relatively short time-frame, the ability to
quickly determine the recovery obligation is critical to the ability to ensure compliance. We appreciate that the drafting
team is attempting to accommodate the notion that a prior Balancing Contingency Event might impact any future events,
but the methodology given for determining the recovery threshold is overly complex, and represents a significant barrier
to a system operator's ability to interpret the requirement in Real Time and respond appropriately. Additionally, the
definition provided for Reportable Balancing Contingency Event inserts confusion as to which value is to be used for
determining MSSC. The definition does not clarify whether the responsible entity is to independently elect whether to use:
A)Its individual MSSC value or the Interconnection values provided B)The Interconnection values provided The definition
should make clear which value is to be used, and under which circumstances (for example, a “lesser of” statement would
be useful, here, if that is the intent)
Individual
Thomas Foltz
American Electric Power
AEP questions if this new version is an improvement over the current BAL-002-1. There are many more terms that are
cross referenced and it will become a risk that operators will struggle to tie all the pieces together. This proposed
standard, while it might be more flexible in some regards, might cause unnecessary confusion. AEP recommends changing
the definition for Balancing Contingency Event to the following: “Any single event described below, or any series of such
otherwise single events, with each separated from the next by less than one minute and, that causes a significant change
to the responsible entity’s ACE caused by 1. Sudden loss of supply (generation or import), not including controlled
shutdown of a unit. 2. Restoration of a load” Reserve Sharing Group: the addition of the “at the time of measurement” is
now stated twice in the same sentence. We believe one of the references should be removed. R1.1 and R1.2 should be
either footnotes or bullet points, but not sub requirements. R2 is very difficult to follow with all of the exceptions.
Furthermore, it would be better to start with the expected obligation and have the exceptions to the rule follow in the
sentence or maybe in a footnote. We do support some amount of a “grace period” during these events, however, what is
the reliability basis for the 5 hour duration?
Individual
Michael Falvo
Independent Electricity System Operator
a. Definition of Balancing Contingency Event: The proposed definition addresses loss of resource, but there is no specific
mention of loss of load which could also cause a change of sudden change to ACE requiring recovery as its loss of resource
counterpart. Please add this condition so that ACE recovery also applies for sudden loss of load, or elaborate why loss of
load is not considered important to correcting ACE or reliability. Also, we believe the words “and interchange” should be
inserted in Item B so that it will read: “imbalance between generation, load and interchange on the Interconnection…” b.
Definition of Reportable Balancing Event: We propose to change the word “or” to “and” in the part: Reportable Balancing
Contingency Event: Any Balancing Contingency Event resulting in a loss of MW output greater than or equal to the lesser

amount of 80 percent of the Most Severe Single Contingency or the amount listed below for the applicable
Interconnection…” since we are addressing the greater value of A (loss of MW output greater than or equal to the lesser
amount of 80 percent of the Most Severe Single Contingency) and B (the amount listed below for the applicable
Interconnection). c. We do not understand the basis of including the definition of Reporting ACE in this standard. The
definition has received industry approval and adopted by the BoT as part of the BAL-001-2 standard. There does not
appear to be any rationale provided in either the Comment Report or the background document or in this Comment Form.
Also, this term is not referenced/used in this standard. d. We commented during the last posting that we didn’t see the
need to define the term Reserve Sharing Group Reporting ACE. This term is not referenced or used in the standard at all.
On the other hand, if including RSG in the Applicability Section is intended to make it a Responsible Entity to simplify
drafting of the requirements (by starting off with “Responsible Entity”), then the RSG should comply with a Reserve
Sharing Group ACE – a term which has not been defined but which we would refer it to be the algebraic sum of the ACE
among the participating BAs. The SDT in its response to our comment indicates that “the use of the term Responsible
Entity requires the inclusion of this definition for Reserve Sharing Groups. The SDT eliminated Requirement R5.1 and R5.2
from the existing standard and moved the language to this definition.” While we agree that the intent of R5.1 and R5.2 of
the existing BAL-002-1 standard have been moved to this standard, we do not believe the important granularity has been
retained. R1 requires the Responsible Entity experiencing a Reportable Balancing Contingency Event shall, within the
Contingency Event Recovery Period, return its ACE to at least:… ACE is currently defined as: “The instantaneous difference
between a Balancing Authority’s net actual and scheduled interchange, taking into account the effects of Frequency Bias,
correction for meter error, and Automatic Time Error Correction (ATEC), if operating in the ATEC mode. ATEC is only
applicable to Balancing Authorities in the Western Interconnection.” We thus interpret “its ACE” in Requirement R1 to
mean a BA’s ACE unless the RSG is explicitly mentioned in the requirement. If this is to be interpreted as the Responsible
Entity’s ACE which also include the RSG as it is included in the Applicability Section, then a term Reserve Sharing Group
ACE will need to be defined, or some explicit language be added to R1 to achieve the purpose that the SDT suggests in its
response to our comments. In brief, the term Reserve Sharing Group Reporting ACE is not needed as it is not referenced
in the standard and serves no purpose. To include the obligation for REG to meet group ACE, a term Reserve Sharing
Group ACE needs to be defined instead. e. In general, we do not agree with the use of this standard to define terms not
directly needed in the standard (e.g. Reporting ACE). f. We do not see the need for R2 when there is already a
requirement to meet the DCS. While the trigger for meeting DCS is the occurrence of a Reportable Balancing Contingency
Event which is linked to the Most Severe Single Contingency may not be at the MSSC level, the requirement to carry a
prescribed amount of reserve is unnecessary for so long as the Responsible Entity meets the DCS requirement. R2 as
proposed presents the “how”, not the “what”. g. This standard needs only to have very simple and plain language to
require each BA and those engage in RSG to: • Meet DCS requirement within 15minutes • Replenish reserve within a
certain time period to prepare for meeting DCS cause by another event • (If necessary) Report the occurrence of
reportable events
Individual
Oliver Burke
Entergy Services, Inc.
Agree
SERC OC Review Group
Individual
Alice Ireland
Xcel Energy
Xcel Energy is voting no on the proposed standard due to issues with R1. It is our opinion that events greater than MSSC
should not be covered at all by the revised BAL-002-2. Instead, those events are appropriately addressed under the
recently approved BAL-001-2 Balancing Authority ACE Limit (BAAL) and TOP-007-0 that sets the limits on exceeding the
IROL or SOL. Standards addressing the BAAL and IROL/SOL require an entity to address the reliability issue within 30
minutes. As part of our rational, if an entity does experience an event greater than its MSSC, it is possible that the entity
will lose some if not all of the units carrying their reserves. If this occurs, the entity is unable to respond with all of its
reserves as required by the proposed R1 in BAL-002-2. Therefore, Xcel Energy recommends the following modifications:
1. Change the definition for Reportable Disturbances to state that only those events 80 percent of the MSSC (or the
appropriate level of loss by interconnection) up to the MSSC would be reportable. This would clarify that events greater
than the entity’s MSSC is not a Reportable Event under the NERC Standards. 2. Simplify the language in R1 to address
multiple events within the period and include the limit of MSSC in this process. 3. The drafting team should also modify
the background document and other related documents to clearly state that events greater than the MSSC are not in
scope of BAL-002-2 and document how these events are already addressed utilizing the BAAL and IROL limitations.
Group
FirstEnergy
Larry Raczkowski
Agree
PJM
Group
SERC OC Review Group
Stuart Goza

Comments: Applicability Section: 4.1.1 A Balancing Authority that is a member of a Reserve Sharing Group is the
Responsible Entity only in periods during which the Balancing Authority is not in active status under the applicable
agreement or governing rules for the Reserve Sharing Group. • Further clarification is requested. Please review previous
versions. The concern in this area is event-by-event participation versus general RSG membership R1 sub-bullet: less the
sum of the magnitudes of all subsequent Balancing Contingency Events that occur Added in draft: “prior to that value of
Reporting ACE” within the Contingency Event Recovery Period, and • Language still remains awkward and the SDT is
requested to continue to refine. • Time line or something visual to clarify the requirement further o The SDT is encouraged
to work on drafting an RSAW for this standard • The SDT is requested to review and confirm that the obligation to report
occurs once the analysis is completed R1.1: SDT is requested to further clarify 1.1 to the extent possible • Question to the
SDT: By having CR Form 1 in the standard would changes to the form have to go through a formal standard revision
change? CR Form 1 is the NERC reporting form. • Consider adding a new R2.1.1 and R2.1.2 to further clarify the
calculation for each of the two different entities (BA and RSG) R2. Except during the Added in draft: “Responsible Entity’s
Contingency Event Disturbance” Recovery Period and Added in draft: “the Responsible Entity’s” Contingency Reserve
Added in draft: “Restoration” Deleted in draft: “Recovery” Period, or during an Energy Emergency Alert Level 2 or 3 Added
in draft: “for the Responsible Entity and for an additional five hours during a given calendar quarter, the” Deleted in draft:
“each” Responsible Entity shall maintain an amount of Contingency Reserve at least equal to its Most Severe Single
Contingency. • R2 The SDT is requested to further clarify how contingency reserves are measured. • R2 The SDT is further
requested to clarify the 5 hour calculation • R2 The SDT is requested to further define the 105 minute We agree with the
current direction of the team to address the directive for the “continent-wide contingency reserve policy” is via with the
“Reserve Guidelines” document being developed. The document should provide guidance on how the BA assesses the
necessary amount of reserves as well as provide simple definitions of the different types of reserves. M2. Each
Responsible Entity shall have dated documentation that demonstrates its Contingency Reserve, averaged over each Clock
Hour, was maintained in accordance with “the amounts identified in Requirement R2 Deleted in draft: “except within the
first 105 minutes following an event requiring the activation of Contingency Reserve”. • M2. Each Responsible Entity shall
have dated documentation that demonstrates its Contingency Reserve, averaged over each Clock Hour, was maintained in
accordance with Requirement 2. • M2: SDT is requested to clarify that the hourly data retention is limited to one number
per hour which represents your contingency reserves for the hour • M2: SDT is requested to add “calendar quarter” to M2
The comments expressed herein represent a consensus of the views of the above named members of the SERC OC Review
Group only and should not be construed as the position of the SERC Reliability Corporation, or its board or its officers.
Group
Associated Electric Cooperative, Inc. - JRO00088
David Dockery
Agree
SERC OC Review Group
Group
ACES Standards Collaborators
Ben Engelby
(1) SAR We have concerns with the proposed revisions to BAL-002, particularly when the changes were neither proposed
in the team’s SAR nor directed in FERC Order No. 693. We do not agree with the use of this standard to introduce nine
new defined terms, and defined terms that are not directly needed in the standard (e.g. Reporting ACE). The SAR directed
the drafting team to clarify the language in the existing standard and to address Order 693 directives. The only two true
requirements in the version zero standard are to recover from reportable events in 15 minutes and replenish reserves 90
minutes thereafter. These actions should be the basis of this standard. (2) Definition of Balancing Contingency Event
There is nothing provided to justify the need of this term. There is a statement in the background document that the
previous version of the standard was “broad and could be interpreted in various manners,” yet there have been no
reliability issues or events that justify the need for further clarification. (3) Definition of Reportable Balancing Contingency
Event We continue to question the definition of Reportable Balancing Contingency Event. There is no explanation for why
Reportable Disturbance is not a satisfactory definition as used in the existing standard and why it is replaced with
Reportable Balancing Contingency Event. The numbers provided for each interconnection appear to be arbitrary. The
background document explains that the drafting team decided “to capture the majority of events having significant impact
on frequency” by setting the threshold to 80 percent of the MSSC, but it did not explain why it was important “to capture
the majority of events.” There is no justification provided for changing the sizes of Reportable Events for the
Interconnections from 80 percent. Where did the thresholds come from? We would like additional clarification and
technical justification. (4) Definition of Pre-Reporting Contingency Event ACE Value Additional justification is necessary to
change the pre-disturbance calculation from an average of 10 to 60 seconds of ACE data prior to the disturbance to a 16second interval. There is no explanation of this in the background document and we cannot support such a change without
a justification for how it supports reliability. Furthermore, it is not consistent with BAL-005-0.2b which requires ACE
calculation on at least a six-second basis. A BA using a six-second sample rate could be viewed as being out of compliance
if an entity used either two (12 seconds) or three (18 seconds) samples since they cannot use exactly 16 seconds of data.
Furthermore, using only two or three samples could lead to unrealistic averages particularly if there are any glitches in the
data. What does an entity do if a scan was skipped or there was a data spike? More samples would make it less likely for
this to be an issue. (5) Definition of Reserve Sharing Group Reporting ACE We believe the definition as proposed is already
a common understanding and is not needed. We simply do not see how it adds value. Further, having multiple definitions
for ACE creates unnecessary confusion. (6) Definition of Contingency Reserve We disagree with the new definition of
Contingency Reserve as it provides no guidance on how to objectively measure reserves. Please strike the last sentence of
the definition. It is an explanation of what may constitute contingency reserve and is not actually part of the definition. It

should be included in the background document. We understand the reason for the inclusion may be in response to a
directive to further the Commission’s policy on expanding the use of DSM. However, the use of DSM has expanded
significantly since the directives were issued and could be said to have been “overcome” by events. It is well understood
within this industry that DSM may be used as a resource. The drafting team could include an explanation in the application
guidelines or the background document that would explain that DSM could be used among other resources. (7) Definition
of Reporting ACE We do not see the benefit of including a three-page definition for this standard. As stated above, we do
not agree with adding terms that are not directly needed in this standard. Furthermore, the kind of information included in
this definition is more appropriate to include in a technical guideline or the application guidelines section. (8) Purpose of
Standard The purpose statement still needs to be modified. We continue to recommend striking the following language
“balances resources and demand,” because these actions are addressed by BAL-001. The purpose of the standard should
state: “To ensure the BA or RSG recover ACE following a Reportable Balancing Contingency Event.” (9) Comments on R1
There is no technical justification for the complexity added to the calculation, and this is out of scope of the SAR. The SAR
does not discuss changing the measurement approach of DCS performance from being calculated and reported on a
quarterly basis. The current approach is well understood in the industry. Therefore, we suggest modifying the standard to
remove the complexity. Proposed Solution for R1: “R1. Except when experiencing an Energy Emergency Alert Level 2 or
Level 3, a Balancing Authority or Reserve Sharing Group experiencing a Reportable Event less than or equal to its MSSC
shall activate sufficient Contingency Reserve to comply with the DCS.” (10) Comments on R2 This requirement will have
significant negative unintended consequences. Reserves are an inventory intended to be used when there is a reliability
need. The first unintended consequence is that BAs are encouraged by this requirement never to deploy their contingency
reserves except for DCS-reportable events. The original Policy 1 noted many reasons for operating reserves. BAs whose
ACE is extremely negative for other reasons would be reluctant to deploy their contingency reserves because the timer
would start ticking on the “available hours” clock. A BA should not be restricted to deploying it only for contingent events.
There may be other reasons for a BA to have a large negative ACE (i.e. units don’t ramp as expected) and the BA should
be free to call upon its contingency reserve to recover ACE in such a situation. Since the FERC directive that is driving this
requirement is to establish a continent wide policy on contingency reserve, a better solution would be for NERC to write an
operating policy describing appropriate uses of various types of contingency reserves. A guideline document would provide
better details for an operating policy than a requirement. The second unintended consequence for those BAs that don’t
withhold contingency reserves for non-DCS events is that they will be obliged to increase the amount of contingencies
they carry so they always have more reserves than their MSSC. This will increase costs to end-users without a
demonstrated need. Furthermore, there is no data indicating that operating reserves carried by BAs today are insufficient.
Proposed Solution for R2: “R2. Except when experiencing an Energy Emergency Alert Level 2 or Level 3, a Balancing
Authority or Reserve Sharing Group experiencing a Reportable Event less than or equal to its MSSC shall replenish its
reserves within 105 minutes of the onset of the Reportable Event.” (11) VSLs for Requirement R1 and Requirement R2 We
disagree with the VSLs for both requirements. The VSLs significantly increase the compliance burden for registered
entities without a technical justification. DCS compliance should continue to be determined by a quarterly average of
response to events. Thus, failure to recover ACE for two events within the same quarter would be a single violation. We
disagree with the proposed VSLs, as they would treat each event as a separate violation. The VSLs for Requirement R2
need to be justified. There is no explanation provided for the values chosen for the various thresholds. For example, the
Lower VSL covers contingency deficiency for a period of 5 to 15 hours. Why shouldn’t this go to 20, 30, 40 or any other
number of hours? Without a justification, we can only assume the numbers were selected arbitrarily. While we understand
from the response to comments that the modifications are intended to reflect actual enforcement practices, there have
been no reliability issues or events that justify the need to shift the DCS to an event-by-event standard. NERC
enforcement staff can submit comments requesting changes to the standards to reflect enforcement practices and FERC
can clearly issue directives for changes once the standard is submitted for their approval. We have not seen any directives
from FERC or comments from NERC enforcement staff regarding the need to revise the quarterly calculation. However,
this raises bigger concerns in that the response implies that enforcement has not been consistent with the current
common understanding of a quarterly calculation for DCS within the standard. If enforcement has not been consistent with
the existing standard, then that issue needs to be addressed outside the standards development process and settled
before the standard is changed to reflect a different period for the calculation DCS compliance. (12) Compliance Section of
Standard The data retention required for the current versions of this standard is too long. BAs submit monthly data to
their regional entities, so they should not be required to retain three years worth of data. No more than six months of data
is necessary. (13) Technical Background Document We agree with the current direction of the team to address the
directive for the “continent-wide contingency reserve policy” is via the “Reserve Guidelines” document being developed.
The document should provide guidance on how the BA assesses the necessary amount of reserves as well as provide
simple definitions of the different types of reserves subject to industry comment. We suggest drafting team retain the
original language regarding the R1 that requirement applies except during EEAs 2 and 3. While we agree with the
compliance exception, the language was moved to component 1.2 and does not comport with the statements from NERC’s
August 10, 2009 filing indicating the purpose and use of numbered components. Specifically, the filing indicates that
numbered “components” will be used for parts that “contribute to the achievement of the reliability objective of the main
requirement, but that individually do not achieve a reliability objective separate from the main requirement.” We do not
believe component or part 1.2 could be viewed as “contributing to the achievement of the reliability objective.” Rather, it
is a compliance exception and should be included as an exception clause similar to the way it was written in the prior
version of the standard. Part 1.1 could be viewed as a paragraph 81 requirement meeting criterion B4 on reporting. NERC
and the Regional Entities already require registered entities to use various reporting forms that are not identified in a
standard. The Rules of Procedure allow NERC and the Regions to request data, thus, we think this is simply not necessary
to document the need to use the CR Form I 1 in the requirement. Thank you for the opportunity to comment.
Individual
John Seelke
Public Service Enterprise Group

Agree
PJM Interconnection, L.L.C.
Individual
Anthony Jablonski
ReliabilityFirst
ReliabilityFirst votes in the Negative 1), ReliabilityFirst believes the introductory paragraph within the Applicability section
is unclear as written, which could lead to unintended compliance implications; 2) the standard should not rely on Energy
Emergency Alert Level 2 or Level 3 which are defined within another standard. The requirements of the standard should
stand on their own merit and not rely on conditions defined within an attachment within another standard and; 3) it is
unclear whether the use of the referenced CR Form 1 is an actual requirement and is enforceable. ReliabilityFirst offers the
following comments for your consideration: 1. Applicability Section – ReliabilityFirst believes the introductory paragraph
within the Applicability section is unclear as written. The language stating “on an individual event basis” is ambiguous and
can lead to questions on the Applicability of this standard. ReliabilityFirst believes the intent of this language is meant to
apply to Reportable Balancing Contingency Events. ReliabilityFirst recommends the following for consideration:
“Applicability is determined on an individual [Reportable Balancing Contingency Events] basis, but this standard does not
apply to a Responsible Entity during periods when the Responsible Entity is in Energy Emergency Alert Level 2 or Level 3.”
2. Reference to Energy Emergency Alert Level 2 or Level 3 - ReliabilityFirst believes referencing Energy Emergency Alert
Level 2 or Level 3 within this standard without defining it within the standard itself is incorrect and troublesome for two
reasons. First, the term Energy Emergency Alert Level is not a NERC defined term and the levels are only referenced in
Attachment 1 of EOP-002-3. Entities which are not familiar with Attachment 1 of EOP-002-3 may have no idea what
constitutes an Energy Emergency Alert Level 2 or Level 3. Second, ReliabilityFirst believes the BAL-002-2 should stand on
its own merit and not rely on conditions within an attachment within another standard. For example, if the Energy
Emergency Alert levels designations ever change (as a result of modifications to Attachment 1 of EOP-002-3), this has the
potential to have an impact on the intent of the BAL-002-2 standard. For the two reasons noted, ReliabilityFirst
recommends formally defining all the Energy Emergency Alert Levels within the NERC Glossary of Terms. This would be a
valid option since this term would now be used in multiple standards (e.g., EOP-002-3 and BAL-002-2). 3. Requirement
R1, Part 1.1 – As written, it is unclear whether this is an actual requirement requiring the entity to use the CR Form 1?
The parent requirement R1 requires the Responsible Entity to return its ACE to either zero or its Pre-Reporting
Contingency Event ACE Value, but does not require the use of the CR Form 1. If it is the intent of the SDT to require the
Responsible Entity to use the CR Form 1, ReliabilityFirst recommends making a new standalone requirement such as “The
Responsible Entity shall use the CR Form 1 for compliance calculations for Reportable Balancing Contingency Events.”
Furthermore, the CR Form 1 is not associated with the standard itself. Without this form being associated as an
attachment or appendix to the standard, how will the Responsible Entity know the location of the referenced form? Also,
ReliabilityFirst believes there may be issues with regulatory approval absent the referenced CR Form 1 being included as
part of the standard. ReliabilityFirst recommends including the CR Form 1 as either an attachment or appendix to the
standard.
Group
SPP Standards Review Group
Robert Rhodes
On BAL-002-2: We would like to see further development of the qualifier ‘sudden loss’. Specifically what comprises a
sudden loss? Naturally we all believe the opening of a unit breaker creates a sudden loss of generation but what about
those events, such as unit runbacks, where there is no clear-cut line of distinction. We have experienced multiple
contingencies where one of the units has tripped out right and the other lingers on for some time before eventually
tripping. Depending upon when the clock starts, this could be interpreted to have occurred within one minute which could
qualify the event as a reportable DCS event. We have talked to multiple REs as well as industry SMEs to determine exactly
what the correct interpretation is in this situation. The way the standard is written there is no single, correct
interpretation. Do we want to incorporate such criteria into the standard or could we find language which would provide
additional clarification to assist in making that determination? This dilemma also extends to situations with imports where
sudden loss is again not clearly defined. This becomes more and more of an operational nightmare when the variability of
intermittent resources is taken into account. Demand-Side Management should be properly handled as a defined term
from the NERC Glossary throughout the standard as well as the Background Document. We ask that the drafting team
provide additional clarification on ‘active status’ found in the Applicability Section 4.1.1. We are most concerned by the
incorporation of the 5-hour exclusion in R2. While on one hand we like the idea of some flexibility in the standard,
providing such flexibility will not improve the reliability of the BES one bit. In fact it would decrease the reliability of the
BES. We suggest removing that language as well as the last paragraph on Page 10 in the Background Document which
details the reasoning behind the exclusion. CR Form 1 requires reporting on a single event basis rather than the quarterly
reporting basis as currently exists. We recommend maintaining the existing quarterly reporting requirement. The
argument here is the same as that used to support the exclusion of contingency events greater than MSSC. That exclusion
is currently found in the Additional Compliance Information Section 1.5 of BAL-002-1 and has been moved into the
requirements of the proposed standard. Likewise, the quarterly reporting criteria contained in the same Additional
Compliance Information section of BAL-002-1 but in Section 2., could just as easily be incorporated into the new standard.
We also support the following comments provided by Xcel Energy. Xcel Energy is voting no on the proposed standard due
to issues with R1. It is our opinion that events greater than MSSC should not be covered at all by the revised BAL-002-2.
Instead, those events are appropriately addressed under the recently approved BAL-001-2 Balancing Authority ACE Limit
(BAAL) and TOP-007-0 that sets the limits on exceeding the IROL or SOL. Standards addressing the BAAL and IROL/SOL

require an entity to address the reliability issue within 30 minutes. Additionally, if an entity does experience an event
greater than its MSSC, it is possible that the entity will lose some if not all of the units carrying their reserves. If it does, it
is unlikely to be able to respond with all of its reserves as required by the proposed R1 in BAL-002-2. Therefore Xcel
Energy recommends the following modifications: 1. The definition for Reportable Disturbances should be changed to state
that only those events 80 percent of the MSSC (or the appropriate level of loss by interconnection) up to the MSSC would
be reportable. Events greater than the entity’s MSSC is not a Reportable Event under the NERC Standards. 2. Simplify the
language in R1 to address multiple events within the period to address concerns in a similar manner. 3. The drafting team
should also modify the background document and other related documents to clearly state that events greater than the
MSSC are not in scope of BAL-002-2 and document how these events are already addressed utilizing the BAAL and IROL
limitations. Xcel Energy recognizes that this proposal will likely cause concern amongst those who participate in the NERC
Resources Subcommittee due to the loss of the quarterly reporting of events greater than the MSSC currently in the
standard. We believe that these quarterly reports, for the evaluation of performance outside of the compliance process,
should not be part of the standard. Instead, if NERC believes this process is needed, create a guideline or other means to
have entities provide the needed information without using compliance with the standard as the reporting process. A clear
separation between standards compliance and data evaluation would provide the industry the clarity of separation
between compliance and data evaluation and study. Background Document: (Page number references are based on the
clean version of the document.) To accentuate the potential for conflict between BAL-002 and EOP-002, we suggest
rewording the first two (2) sentences of the last paragraph on Page 4 to read: ‘Additionally, possible conflict existed
between BAL-002 and EOP-002 as to when an entity could deploy its contingency reserve. To eliminate the conflict and to
assure…’ The following terms are contained in the NERC Glossary and should be consistently capitalized in the document:
Operating Reserve Contingency Reserve Spinning Reserve Non-Spinning Reserve Frequency Response Obligation (new
term associated with BAL-003-1) We recommend rewriting the first line of the second paragraph under Background and
Rationale on Page 6 to read: ‘By incorporating new definitions, including the modification of existing definitions, with the
proposed R1 above, the …’ Insert a ‘the’ in front of Consortium in the first line of the last paragraph on Page 6. Rewrite
the third line of the paragraph under Violation Severity Levels on Page 7 to read: ‘Contingency Reserve available and
whether it has sufficient…’ Insert a ‘that’ in front of BAL-002 in the first line of the second paragraph under Background
and Rationale on Page 10.
Group
Duke Energy
Michael Lowman
Duke Energy’s position is summarized as follows: a) This standard should not require 15-minute recovery for events
greater than the MSSC, b) The standard should allow responsible entities to choose a lower reportable threshold and
measure performance on a quarterly basis, and c) Tracking hourly amounts of Contingency Reserves maintained should
be removed from this draft Standard and added to the guideline document. Regarding Requirement R1, Duke Energy
would like to reiterate that no technical justification has been provided for requiring a 15-minute recovery from a
Balancing Contingency Event. We believe those on the Standard Drafting Team also active in the development BAL-001-2
would acknowledge that the risk of any other significant event on the Interconnection occurring within the first event’s
Contingency Event Recovery Period or Contingency Reserve Restoration Period is so negligible that the risk does not on its
own warrant such immediate action or compliance assessed on an event-by-event basis. It is our opinion that the
recently-approved Balancing Authority ACE Limit (BAAL) in BAL-001-2 will drive the actions necessary to maintain
Interconnection frequency within acceptable limits, as any event causing a large change in ACE and impacting frequency
will be under that Standard’s scrutiny. However, Duke Energy believes there is value in having a Reliability Standard that
requires retaining contingency reserves capable of such immediate response and periodically testing the Balancing
Authority’s ability under DCS to implement its reserves. When DCS is viewed as a test of reserves maintained, one can
understand the position that: a) For consistency across all Balancing Authorities, testing such capability for losses 80%
and greater of the MSSC should typically cover each Balancing Authority reporting at least one event per quarter, b) Such
tests should not include unplanned events above the MSSC, c) There shouldn’t be an attempt to measure that reserves
are maintained hourly, the proof is in the results, d) As a test to demonstrate reserves are maintained, the industry
accepts that recovery at times may move Interconnection frequency further from scheduled frequency, such as during
certain off-peak periods of high frequency, e) There is no need to capture every possible event under the scope of what’s
tested – it is more important that the criteria be clear to the operator (generation trip) on what’s being tested, f) Recovery
within 15 minutes is a reasonable expectation, as we don’t want the contingent Balancing Authority leaning on the
Interconnection support others provide too long, and g) Recovery within 15 minutes is a reasonable expectation, as the
loss may be causing unanticipated flows (good or bad) that the contingent Balancing Authority should be first to correct It
is our opinion that the points above all factored into the original approval of DCS, along with the industry acceptance that
if the DCS was not met over a calendar quarter, that additional contingency reserves would be carried until Balancing
Authority demonstrated its capability to meet those expectations. The quarterly reporting allowed for recognition that
performance for every event may not be perfect, and that measuring compliance over the quarter is a better measure of
the entity’s overall performance and reserves maintained. Our points above are made as we believe that upon
implementation of the BAAL, the value in retaining BAL-002 is in having a simple, results-based Standard to measure that
reserves are adequately being maintained. We believe that this draft Standard goes beyond what is needed for reliable
operations. It is our opinion that not all Regions share the concern that the 15-minute recovery is needed to mitigate
transmission congestion problems, and we would suggest that perhaps such concerns should be addressed at the regional
level. Duke Energy supports the comments of Xcel Energy regarding the proposed Requirement R1. It is our opinion that
events greater than the MSSC should not be held to the 15-minute recovery criteria required under the revised BAL-0022. Events greater than MSSC, typically driven by multiple unforeseen contingencies on the system, may require the
Balancing Authority to coordinate its activities with the Transmission Operator for consideration of the transmission impact

of any reserve deployment or Interchange options. Under such circumstances we believe that the recently approved BAL001-2 Balancing Authority ACE Limit (BAAL) and current TOP-007-0 that sets the limits on exceeding the IROL or SOL
should be the Reliability Standards guiding the response required. In addition, and as part of our rationale, if an entity
does experience an event greater than its MSSC, it is possible that the entity will lose some if not all of the units carrying
their reserves. If this occurs, the entity is unable to respond with all of its reserves as required by the proposed R1 in BAL002-2. Therefore, Duke Energy supports the following modifications suggested by Xcel Energy: 1. Change the definition
for Reportable Disturbances to state that only those events 80 percent of the MSSC (or the appropriate level of loss by
Interconnection) up to the MSSC would be reportable; this would clarify that an event greater than the entity’s MSSC is
not a Reportable Event under the NERC Standards. 2. Simplify the language in R1 to address multiple events within the
period and include the limit of MSSC in this process. 3. The drafting team should also modify the background document
and other related documents to clearly state that events greater than the MSSC are not in scope of BAL-002-2 and
document how these events are already addressed utilizing the BAAL and IROL limitations. Duke Energy disagrees with
measuring performance on an event-by-event basis. We believe such a metric will have a detrimental impact on reliability
as responsible entities will have no reason to bring more resource losses under the scope of required compliance. The
current standard, which allows a lower reportable threshold to be used in quarterly reporting, benefits the Interconnection
and results in demonstrated activity under DCS for events that this proposed standard will push under BAL-001. Duke
Energy also supports the comments of the SERC OC Review Team and agrees with the current direction of the team to
address the directive for the “continent-wide contingency reserve policy” is via the “Reserve Guidelines” document being
developed. The document should provide guidance on how the BA assesses the necessary amount of reserves as well as
provide simple definitions of the different types of reserves. Regarding Requirement R2: Duke Energy agrees with the
language in this Standard that recognizes that Contingency Reserves may be utilized to serve load during an Energy
Emergency Alert Level 2 or 3. However, it is our opinion that this Standard should remain a results-based Standard and
not burden responsible entities with such tracking of reserves maintained. Though an hourly average is proposed, it is not
practical for a BA to track its Contingency Reserves in a manner where the System Operator would make the choice to
increase its Contingency Reserves above the MSSC if it happened to drop below its MSSC for some time in the same hour
– it is an unnecessary activity to bring into real-time operations. In addition, tracking reserves to this extent may result in
Balancing Authorities not balancing their systems, to the extent allowed under BAL-001, in order to not dip into the
Contingency Reserves which could, and should, be utilized as needed. Duke Energy recommends removing the hourly
tracking of reserves from this standard and adding it to the guideline document. Though suggestions have been provided,
Duke Energy does not support the adoption of Requirement R2 and agrees with the comments provided by MISO and
SERC OC Review Team. Performance under the existing BAL-002 has been stellar without the need for an additional
requirement to track Contingency Reserves to the extent prescribed. The current DCS is a very effective results-based
standard. The existence of a requirement such as R2 will result in inefficient utilization of resources, increased costs,
inaccurate representation of resource capability, and other negative consequences with no benefit to reliability. Finally,
Duke Energy suggests the following changes to the definitions in this standard: Duke Energy believes that Item B of
Balancing Contingency Event should be removed because it is already covered under Item A. If the SDT disagrees, then
item B should retain “the change to the responsible entity’s ACE.” The proposed draft language in item B, “imbalance
between generation and load to the interconnection”, opens up the possibility that upon the loss of transmission, the
source Balancing Authority may continue to generate and sink Balancing Authority may continue to receive the energy
without sufficient remaining transmission in place for the transfer. This will in turn overload facilities but not be captured
as an “imbalance between generation and load on the Interconnection”. See comments on proposed definitions beginning
on next page. Proposed by SDT: Balancing Contingency Event: Any single event described in Subsections (A), (B), or (C)
below, or any series of such otherwise single events, with each separated from the next by less than one minute. A.
Sudden Loss of generation: a. Due to i. Unit tripping, ii. Loss of generator Interconnection Facility resulting in isolation of
the generator from the Bulk Electric System or from the responsible entity’s electric system, or iii. Sudden unplanned
outage of transmission Facility; b. And, that causes an unexpected change to the responsible entity’s ACE; B. Sudden loss
of an import, due to forced outage of transmission equipment that causes an unexpected imbalance between generation
and load on the Interconnectionchange to the responsible entity’s ACE. C. Sudden restorationloss of a known load that
was used as a resource that causes an unexpected change to the responsible entity’s ACE. Suggested: Balancing
Contingency Event: Any single event described in Subsections (I) or (II) below, or any series of such otherwise single
events, with each separated from the next by less than one minute. I. Sudden loss of generation that causes an
unexpected change to the responsible entity’s ACE due to: a. Unit tripping, b. Loss of generator Interconnection Facility
resulting in isolation of the generator from the Bulk Electric System or from the responsible entity’s electric system, or c.
Sudden unplanned outage of transmission Facility II. Sudden restoration of a load that was used as a resource that causes
an unexpected change to the responsible entity’s ACE. NOTE: F Duke Energy took part A.a. and A.b. of the SDT proposed
definition and incorporated it into “I”; Sudden loss of generation that causes an unexpected change to the responsible
entity’s ACE due to: F Changed the numbering from A. to I., B to II. and changed i., ii., iii. to a., b., c.
Proposed by
SDT: Most Severe Single Contingency (MSSC): The Balancing Contingency Event, due to a single contingency, that would
result in the greatest loss (measured in MW) of resource output used by the Reserve Sharing Group (RSG) or a Balancing
Authority that is not participating as a member of a RSG at the time of the event to meet firm system load and export
obligation (excluding export obligation for which Contingency Reserve obligations are being met by the sink Balancing
Authority). Suggested: Most Severe Single Contingency (MSSC): The magnitude of a single Balancing Contingency Event
as a result of the greatest loss (measured in MW) of resource output used by a Reserve Serving Group (RSG) or a
Balancing Authority that is not a member of an RSG. Proposed by SDT: Reportable Balancing Contingency Event: Any
Balancing Contingency Event resulting in a loss of MW output greater than or equal to the lesser amount of 80 percent of
the Most Severe Single Contingency or the amount listed below for the applicable Interconnection500 MW and occurring
within a rolling one-minute interval based on EMS scan rate data. The 80% threshold may be reduced upon written
notification to the Regional Entity. • Eastern Interconnection - 900 MW • Western Interconnection – 500 MW • ERCOT –
800 MW • Quebec – 500 MW Suggested: Reportable Balancing Contingency Event: Any Balancing Contingency Event
resulting in a loss of MW output that causes an ACE change greater than or equal to 80% of a Balancing Authority’s or

Reserve Sharing Group’s Most Severe Single Contingency or applicable amount listed below for each Interconnection, that
occurs within a rolling one-minute interval of EMS scan rate data. The 80% threshold may be reduced upon written
notification to the Regional Entity. • Eastern Interconnection - 900 MW • Western Interconnection – 500 MW • ERCOT –
800 MW • Quebec – 500 MW Proposed by SDT: Contingency Reserve: The provision of capacity that may be deployed by
the Balancing Authority to respond to a Balancing Contingency Event and other contingency requirements (such as Energy
Emergency Alerts Level 2 or Level 3) as specified in the associated EOP standard). The capacity may be provided by
resources such as Demand Side Management (DSM), Interruptible Load and unloaded generation. Suggested:
Contingency Reserve: The provision of capacity that may be deployed by the Balancing Authority to respond to a
Balancing Contingency Event or contingency requirements such as an Energy Emergency Alert Level 1 or Level 2 as
specified in the associated EOP Reliability Standard. The capacity may be provided by resources such as Demand Side
Management (DSM), Interruptible Load and unloaded generation. NOTE: Replaced EEA Level 2 or 3 with EEA Level 1 or 2
in the definition. Contingency Reserve is already being utilized at EEA Level 3. I kept EEA Level 2 in the definition since
Demand-side Management and Interruption of non-firm end use loads can be used, which both are resources of capacity
used for Contingency Reserve. I’ve provided some detail below for EEA 2 and 3: • EEA 2 – Load management procedures
in effect F the entity is no longer able to provide its customers’ expected energy requirements and is designated an Energy
Deficient Entity. F Energy Deficient Entity has implemented procedures up to, but excluding interruption of firm load
commitments….DSM, Interruptible Load, etc. can be used time permitting • EEA 3 – Firm load interruption imminent or in
progress (Contingency Reserve is already being used) Proposed by SDT: Refer to project page or NERC Glossary of Terms
Suggested: Reporting ACE: Duke Energy is unsure why the SDT needs to include Reporting ACE as a revised definition in
the proposed BAL-002-2 standard. This same definition has already been approved by the BOT and is in the NERC
Glossary of Terms with no FERC Approval Date.
Group
Kansas City Power & Light
Brett Holland
Agree
SPP - Robert Rhodes
Individual
Texas Reliability Entity
Texas Reliability Entity
In R2, we feel that the five hours grace period for failing to maintain sufficient Contingency Reserves is too long, especially
since Contingency Event Recovery Periods and EEAs are excluded. We recommend that there should be no grace period,
and that the VSLs can be used to apply higher penalties for longer violations: 0-3 hours for lower VSL, 3-5 for moderate
VSL, 5-10 for high VSL, and >10 for severe VSL.
Group
PPL NERC Registered Affiliates
Brent Ingebrigtson
These comments are submitted on behalf of the following PPL NERC Registered Affiliates (PPL): Louisville Gas and Electric
Company and Kentucky Utilities Company; PPL Electric Utilities Corporation, PPL EnergyPlus, LLC; and PPL Generation,
LLC, PPL; Susquehanna, LLC; and PPL Montana, LLC. The PPL NERC Registered Affiliates are registered in six regions
(MRO, NPCC, RFC, SERC, SPP, and WECC) for one or more of the following NERC functions: BA, DP, GO, GOP, IA, LSE, PA,
PSE, RP, TO, TOP, TP, and TSP. Applicability Section: 4.1.1 needs clarification. It is unclear what “not in active status”
means. Specifically, it is unclear whether a BA may be in “active status” by simply being under an RSG agreement and
governing rules. It is unclear whether a BA not choosing to call on RSG assistance for any single Balancing Contingency
Event (whether Reportable or not) would be considered “not in active status.” This makes R2 unclear as to whether and
when the BA is the Responsible Entity, what MSSC and reporting threshold would apply, or whether the 5-hour quarterly
clock applies to the BA but not the RSG. Suggested language: A Balancing Authority that is a member of a Reserve
Sharing Group is the Responsible Entity only in periods during which the Balancing Authority cannot rely upon the Reserve
Sharing Group under the applicable agreement or governing rules for the Reserve Sharing Group. Rather than prescribe
the commercial arrangements between members of a RSG, the above language respects whatever arrangements RSG
members have put in place recognizing that these arrangements must enable the group and its members to remain in
compliance with all applicable requirements. In R1, the added language “prior to that value of Reporting ACE” is
confusing. It is unclear how a Balancing Contingency Event can be both subsequent and prior to a value of Reporting Ace.
PPL cannot suggest a solution as we don’t understand the intent of the added language. In R2, the calculation/evaluation
of the 5 hour/quarter “exception clock” needs explanation. It is unclear whether a single EMS scan, where Contingency
Reserve is calculated at less than MSSC, counts as an hour. It is unclear whether it is evaluated as the average, mean or
median of the Contingency Reserves held for a Clock Hour. M2 specifies a Clock Hour as the time increment to be used –
Clock Hour should also be stated in R2. PPL suggests that the 5-hour exception clock be based on the Clock Hour average
amount of Contingency Reserves held by the Responsible Entity (BA or RSG) for the calendar quarter. As the proposed
standard is significantly different from the historical/existing DCS, a draft RSAW should be provided so Responsible
Entities can have an indication of how compliance will be evaluated.
Individual
Si Truc PHAN
Hydro-Québec TransÉnergie

We believe that this new draft is an improvement to the actual standard. However, there are three comments that we
think should be considered in order to improve the actual. First, the Balancing Contingency Event definition uses the
terminology “Any single event…” where the Most Severe Single Contingency definition uses the terminology “…due to a
single contingency…” Hydro-Quebec TransÉnergie believes there is no difference between these two terminologies. In
order to reduce the risk of misinterpretation, we recommend to be consistent in the definitions. Second, some
contingencies occur within the Quebec Interconnection where generation is loss as well as load at the same time. For
example, there are contingencies where 1900 MW of generation is loss and 1600 MW of DC converters at the same time
which result in the net loss for the BA/Interconnection of 300 MW. The result causes only a small ACE change under the
Reportable Balancing Contingency Event threshold. In addition, the 1600 MW of DC converter loss would probably be
reported by another entity as a DCS due to a loss of an import. For this reason, Hydro-Quebec TransÉnergie suggests that
the Balancing Contingency Event and the Reportable Balancing Contingency Event definitions would be more accurate if
they would include the notion of net loss for the BA instead of only the generator MW output. Finally, as for the Reportable
Balancing Contingency Event threshold, we feel that the 500 MW threshold for the Quebec Interconnection should be
revised to 800MW. The actual threshold is set at 80% of MSSC which corresponds generally around 800 MW. This value
already traps events that are significant for the Interconnection and truly measures events where contingency reserve is
being deployed by operator actions. A too low threshold might capture events that are recovered with frequency response
and AGC action, which are deployed quickly after the event since we are in a single BA Interconnection. We believe that
the proposed threshold in the draft will increase the reporting without any improvement in measuring contingency reserve
deployment. We would like to thank the SDT in advance for considering these comments.
Individual
Robert Blohm
Keen Resources Ltd.
Per my comments in the prior round, "Contingency Reserve" as here defined is a muddle because it includes the
Frequency Responsive reserve deployed to first-respond to a Contingency Event. In fact, proper operation requires that
properly-defined Contingency Reserve ultimately replace that Frequency Responsive Reserve deployed, as well as replace
Regulating Reserve deployed in the interim, so that Regulating Reserve may be freed to respond to normal operating
variability. Reserve needs to be defined by the physical nature of the reserve, not by any temporary use to which the
reserve may be put. A more immediate solution to the unclarity is to rename the term here defined as "Reserve Used for
Contingencies" rather than "Contingency Reserve" whose meaning would be more like reserve "assigned" to
contingencies, just like Frequency Responsive Reserve is assigned to quickly arresting and holding frequency change.
Replace in R1, in 2 places, "prior to THAT value of Reporting ACE" by "prior to, OR WHEN, ATTAINING THE MOST
POSITIVE value of reporting ACE" These changes also need to be made in the Background Document's restatement of R1.
In R2 VSLs, in 3 places, "less than or equal to" violates the rules of grammar and should be replaced by "no more than".
In the first two bullets on page 7 of the Background Document, to be consistent with the Standard's R1, 1. the words
"occurring before or when attaining the most positive Recording ACE" need to be inserted after the words "subsequent
event, if any," and 2. the words "before or when attaining the most positive Recording ACE" need to be inserted after the
words "subsequent events occurring". In the Background Document formulas the definition of SUM_SUBSQ requires
appending "and before or when attaining the most positive Reporting ACE during that period" to make it consistent with
the standard's R1. The formulas in the Background document are not in the standard mathematical form used in all other
NERC standards and documents just because the CR Form 1 in which they are also entered is in Excel format that does
not allow for entry of standard mathematical notation. This technical shortcoming in a spreadsheet calculation form should
not impair the explanatory clarity of the Background Document where standard uniform mathematical notation should be
the governing form of the standard, even if the CR Form 1 needs to convert it into machine-language computerese in
order to repeat the explanation already given in the Background document. For replacement in the Background Document
I provide at this link http://www.blohm.cnc.net/BAL002formulas the standard mathematical form of these formulas
because this comment form does not allow the entry of mathematical notation (in particular, subscripting). Grammar: on
page 7 of the Background Document, paragraph 2, "entity(s)" should be "entity's". Formatting: at the bottom of page 7,
1st paragraph of the "Compliance Calculation" section, two of the three lines should not be indented. Replacement in the
current CR Form 1 spreadsheet of the word "claimed" by the word "included" on lines 40 and 41 of the Instructions tab is
intended presumably to remove the optionality of recognizing subsequent events during the recovery period, and to be
consistent with the requirement in the Standard's R1 of recognizing "all" the events before the most positive ACE and
none after, for purposes of discounting the recovery requirement. If so, I support the consistency.
Individual
Brian Shanahan
National Grid Transmission Operations
Agree
We support the NPCC RSC's comments on this Standard.
Individual
Howard Illian
Energy Mark, Inc.
None
Individual

David Jendras
Ameren
Agree
We are generally supportive of the SERC OC Review Group Comments for BAL-002-2.
Individual
Catherine Wesley1
PJM Interconnection
General Comments We appreciate the opportunity to comment and the work the drafting team has contributed to this
effort. We have concerns with some of the changes proposed to BAL-002 absent demonstrated need, particularly when the
changes were not proposed in the team’s SAR nor directed in Order No. 693. The SAR for the drafting team was basically
to clean up the clutter in the standard and address Order No 693 directives. The only two true requirements in the
standard are to recover from reportable events in 15 minutes and replenish reserves 90 minutes thereafter. Beyond this,
we recommend focusing on the intent of the 693 directives. The NERC Resources Subcommittee performed analysis when
DCS was first developed and found that the average time to recover from large unit trips was roughly 15 minutes. Recent
analysis for BAL-003 has found that all four Interconnections recover from large unit trips in about 5 minutes. Compared
to where we were 10 years ago, performance has been stellar. BAL-002 is working quite well today. If the definition for a
Reportable Balancing Contingency Event is approved, what happens to the current definition for a Reportable Disturbance
in the NERC Glossary? Does the existence of these two definitions create confusion or ambiguity? Comments on R1
Complexity. There is no reasoning provided for the complexity added to the calculation. The current approach is well
understood by the industry. The SAR does not discuss changing the measurement approach. Events > MSSC. We have
concerns with the new performance calculation for events greater than the Most Severe Single Contingency (MSSC). First,
it appears the calculation would not work if the generators that were lost were the units carrying the Balancing Authority’s
reserves. Our second concern is that this proposed change may likely negatively impact reliability. It appears that the
drafting team is attempting to put a measure on events > MSSC to ensure a Balancing Authority responds quickly to large
events. While laudable in concept, multi-contingent events are typically associated with something wider happening on the
transmission system. The priority for operators when something major occurs is transmission security rather than rushing
to achieve a zero ACE. It should be remembered there are protective backstops in place absent this proposed change: •
The IROL standards still require operators to take whatever action is necessary to prevent cascading with the next
contingency, to include shedding load or redispatch. • The new BAL-001 standard will require the Balancing Authority to
take action within 30 minutes to get frequency back within acceptable bounds. • The Energy Emergency Alert process still
exists to address any reserve shortfall. Implementing a requirement that causes a knee-jerk ramping of all generation
following a multi-contingent event may likely exacerbate congestion. With the recent approval of BAL-001-2 and future
implementation of BAAL we question the appropriateness of requiring a BA to continue to drive their individual ACE higher
under this standard after Interconnection frequency has already returned to schedule. This scenario would not be in the
best interest of Interconnection reliability and respectfully suggest the SDT consider language that considers the
contingent BA’s recovery period satisfied when Interconnection frequency returns to scheduled frequency. Reporting. We
support the current process whereby events > MSSC are reported. We have no problem with the report form asking for
additional data for events > MSSC that are used in the Events Analysis and Reliability Assessment and Performance
Analysis (RAPA) processes, but believe it is a mistake to add a performance expectation for events > MSSC. The preamble
of the original Operating Manual on which we have built our standards outlined a premise that we operate to N-1 and
make best efforts to protect the system for events greater than this. All CONTROL AREAS shall operate so that instability,
uncontrolled separation, or cascading outages will not occur as a result of the most severe single contingency. Multiple
outages of a credible nature shall also be examined and, when practical, the CONTROL AREAS shall operate to protect
against instability, uncontrolled separation, or cascading outages resulting from these multiple outages. DCS performance
is calculated and reported to the RRO on a quarterly basis. R1.1 states that CR Form 1 is the exclusive ‘reporting form’ but
Measure 1 states it is to be maintained and provided upon request. R1.1 adds complexity and confusion to the reporting
process. If CR Form 1 is to be used only for reporting a violation to NERC then this needs to be clarified in the requirement
to avoid misinterpretation and confusion regarding NERC reporting versus RRO reporting. Comments on R2 This
requirement proposes another major change to what is a superior approach of performance-based standards. This
requirement will also likely have significant negative unintended consequences. Reserves are an inventory intended to be
used when there is a reliability need. The original Policy 1 listed multiple reasons for carrying operating reserves (errors in
forecasting, generation and transmission equipment unavailability, number and size of generating units, system
equipment forced outage rates, maintenance schedules, regulating requirements, and Regional and system load diversity).
We believe the addition of a commodity measure will have unintended consequences. BAs are encouraged by this
requirement never to deploy their contingency reserves except for DCS-reportable events. BAs whose ACE is extremely
negative for other reasons would be reluctant to deploy their contingency reserves because the timer would start ticking
on the “available hours” clock. Reserves should be used when there is a reliability need that may or may not be caused by
the loss of a resource. This requirement encourages BA’s to withhold deployment of contingency reserves except for DCS
reportable disturbances. For example: • If a BA’s ACE is dragging into the top of the hour, along with Interconnection
frequency, due to schedule changes and slow unit response, this requirement incentivizes the BA to withhold deploying
reserves. • If a BA is approaching an IROL that could be mitigated by deploying contingency reserves, this requirement
penalizes the BA for doing so, even though the result would benefit Interconnection reliability. • A BA would be penalized
for using it’s contingency reserves to provide assistance to a neighboring BA(s) if no reserve sharing agreement exists.
This will likely have an adverse impact on Interconnection cooperation and reliability. • R2 does not take into account the
comingled relationship between contingency reserves and frequency responsive reserves. For example, a BA could
maintain additional synchronized reserves to cover both the MSSC and FRO requirements set forth in BAL-002 & BAL-003
as long as sufficient generating units have governors in service with proper control settings. During a frequency event

outside their balancing area, a BA could be penalized under the hourly average terms of BAL-002 R2 if they provide
frequency response above & beyond their FRO that causes contingency reserves to go below MSSC. Essentially, this
requirement could encourage BA’s to limit frequency responsive reserves. BAs that don’t withhold contingency reserves for
non-DCS events will be obliged to increase the amount of contingency reserves they carry so they always have more
contingency reserves than their MSSC. This will increase costs to our customers without a demonstrated need. DCS
performance in North America has been stellar compared to what was considered adequate performance under Policy 1.
The standard provides no clear definition on how contingency reserves are measured. Does it include all generation
headroom available in 10 minutes? In 15 minutes? What about resources that are also providing AGC? Does their
instantaneous headroom count? Are load resources available in 15 minutes or 10 minutes counted? What about demand
response resources that aren’t directly measured? Finally, are the hours referenced in the standard clock-hours, any
contiguous 60 minute period, or the total minutes in a quarter divided by 60? If we agreed with R2, which we do not, we
believe that this ‘quarterly forgiveness’ is confusing, has not been adequately defined, and could easily be misinterpreted.
Proposed Solutions The SAR for the drafting team was basically to clean up the clutter in the standard and address Order
No 693 directives. The only two true requirements in the standard are to recover from reportable events in 15 minutes
and replenish reserves 90 minutes thereafter. These should be the basis of this standard. We recommend the two core
requirements be: R1. Except when experiencing an Energy Emergency Alert Level 2 or Level 3, a Balancing Authority or
Reserve Sharing Group experiencing a Reportable Event less than or equal to its MSSC shall activate sufficient
Contingency Reserve to comply with the DCS. Events > than MSSC are reported, but do not factor into the compliance
calculation. R2. Except when experiencing an Energy Emergency Alert Level 2 or Level 3, a Balancing Authority or Reserve
Sharing Group experiencing a Reportable Event less than or equal to its MSSC shall replenish its reserves within 105
minutes of the onset of the Reportable Event. To provide clarity, the compliance section of the standard should describe
the reporting approach for events > MSSC. The “Reserve Guidelines” document should be expanded to explain that BAs
are expected to make best efforts to recover from events > MSSC, but that transmission security takes precedence. Either
the Reserve Guidelines document, the compliance section of the standard, or an appendix to the standard should include
the reporting form for DCS. Alternatively, the drafting team could create the report in spreadsheet form. The form should
include the basis of the MSSC and clarify that the form is to be used for NERC reporting and under what conditions;
periodic or only upon non-compliance. The sizes of the Reportable Events for the Interconnections proposed by the
drafting team are acceptable and meet the intent of one of the 693 directives.
Individual
Denise M. Lietz
Puget Sound Energy
In section A of the definition of Balancing Contingency Event, the word "Loss" should not be capitalized since it is not a
defined term. In the definition of Most Severe Single Contingency, the drafting team should capitalize "contingency" where
it is used in the phrase "due to a single contingency". "Contingency" is defined in the NERC Glossary and it is confusing to
use an undefined version of a defined term, because that use leads to the question about how this version of
"contingency" differs from the defined version. In addition, the defined term looks appropriate to use in this context. The
last full sentence of the definition of "Reportable Balancing Contingency Event" does not indicate who can reduce the 80%
threshold. It should instead read "A Responsible Entity may reduce the 80% threshold upon written notification to the
Regional Entity." The first sentence of R1 should require recovery of “Reporting ACE” (right now it just applies to "ACE").
The use of the phrase "prior to that value of Reporting ACE" in the two bullets of R1 that address subsequent events is
confusing and ambiguous. It is difficult to suggest alternative language without understanding the phrase's intended
purpose. Including the language about energy emergencies in the applicability section and in the requirements has the
potential to create ambiguity in the application of the standard. The better approach is to deal with this matter in the
applicability section alone. The Severe VSL for requirement R1 leaves a situation where there was no recovery at all out of
the equation entirely. This VSL could instead read “The Responsible Entity failed to provide any of the required recovery or
recovered partially … but recovered 70% or less of required recovery.”
Group
ISO-RTO Council Standards Review Committee
Terry Bilke
General Comments We appreciate the opportunity to comment and the work the drafting team has contributed to this
effort. We have concerns with some of the changes proposed to BAL-002 absent demonstrated need, particularly when the
changes were not proposed in the team’s SAR nor directed in Order No. 693. The SAR for the drafting team was basically
to clean up the V0 clutter in the standard and address Order No 693 directives. The only two true requirements in the V0
standard are to recover from reportable events in 15 minutes and replenish reserves 90 minutes thereafter. Beyond this,
we recommend focusing on the intent of the 693 directives. The NERC Resources Subcommittee performed analysis when
DCS was first developed and found that the average time to recover from large unit trips was roughly 15 minutes. Recent
analysis for BAL-003 has found that all four Interconnections recover from large unit trips in about 5 minutes. Compared
to where we were 10 years ago, performance has been stellar. BAL-002 is working quite well today. We don’t agree with
the use of this standard to define terms not directly needed in the standard (e.g. Reporting ACE). We disagree with the
new definition of Contingency Reserve as it provides no guidance on how to objectively measure reserves. Definitions
Reserve Sharing Reporting ACE. The proposed term Reserve Sharing Group Reporting ACE is not needed as it is not
referenced in the standard and serves no purpose. Pre-Reporting Contingency Event ACE Value. The measurement
process used to date has been effective. We see no reason to add this level of complexity. Comments on R1 Complexity.
There is no reasoning provided for the complexity added to the calculation. The current approach is well understood by the
industry. The SAR does not discuss changing the measurement approach. Events > MSSC. We have concerns with the

new performance calculation for events greater than the Most Severe Single Contingency (MSSC). First, it appears the
calculation would not work if the generators that were lost were the units carrying the Balancing Authority’s reserves. Our
second concern is that this proposed change may likely negatively impact reliability. It appears that the drafting team is
attempting to put a measure on events > MSSC to ensure a Balancing Authority responds quickly to large events. While
laudable in concept, multi-contingent events are typically associated with something wider happening on the transmission
system. The priority for operators when something major occurs is transmission security rather than rushing to achieve a
zero ACE. It should be remembered there are protective backstops in place absent this proposed change: • The IROL
standards still require operators to take whatever action is necessary to prevent cascading with the next contingency, to
include shedding load or redispatch. • The new BAL-001 standard will require the Balancing Authority to take action within
30 minutes to get frequency back within acceptable bounds. • The Energy Emergency Alert process still exists to address
any reserve shortfall. Implementing a requirement that causes a knee-jerk ramping of all generation following a multicontingent event may likely exacerbate congestion. We support the current process whereby events > MSSC are reported.
We have no problem with the report form asking for additional data for events > MSSC that are used in the Events
Analysis and Reliability Assessment and Performance Analysis (RAPA) processes, but believe it is a mistake to add a
performance expectation for events > MSSC. The preamble of the original Operating Manual on which we have built our
standards outlined a premise that we operate to N-1 and make best efforts to protect the system for events greater than
this. Here is the text from the Operating Manual. All CONTROL AREAS shall operate so that instability, uncontrolled
separation, or cascading outages will not occur as a result of the most severe single contingency. Multiple outages of a
credible nature shall also be examined and, when practical, the CONTROL AREAS shall operate to protect against
instability, uncontrolled separation, or cascading outages resulting from these multiple outages. Change from Quarterly
Metric. DCS performance has always been calculated and reported on a quarterly basis. This is no different than CPS1 and
CPS2 whose performance is based on annual and monthly calculations. There have been no reliability issues that point to
the need for making the DCS an event-by-event standard as is now proposed. We believe this proposed change will lead
to changes in how Reserve Sharing Groups will select events, only reporting those very large events rather than allowing
members to call for reserves for smaller contingencies. This is a step backward for no defined need. ACE Definition. R1
requires the Responsible Entity experiencing a Reportable Balancing Contingency Event shall, within the Contingency
Event Recovery Period, return its ACE to at least:…… ACE is currently defined as: “The instantaneous difference between a
Balancing Authority’s net actual and scheduled interchange, taking into account the effects of Frequency Bias, correction
for meter error, and Automatic Time Error Correction (ATEC), if operating in the ATEC mode. ATEC is only applicable to
Balancing Authorities in the Western Interconnection.” We thus interpret “its ACE” in Requirement R1 to mean a BA’s ACE
unless the RSG is explicitly mentioned in the requirement. If this is to be interpreted as the Responsible Entity’s ACE which
also includes the RSG since it is included in the Applicability Section, then a term Reserve Sharing Group ACE will need to
be defined, or some explicit language be added to R1 to achieve the purpose that the SDT suggests in its response to our
comments. Comments on R2 This requirement proposes another major change to what is a superior approach of
performance-based standards. This requirement will also likely have significant negative unintended consequences.
Reserves are an inventory intended to be used when there is a reliability need. The original Policy 1 listed multiple reasons
for carrying operating reserves (errors in forecasting, generation and transmission equipment unavailability, number and
size of generating units, system equipment forced outage rates, maintenance schedules, regulating requirements, and
Regional and system load diversity). We believe the addition of a commodity measure will have unintended consequences.
The first unintended consequence is that BAs are encouraged by this requirement never to deploy their contingency
reserves except for DCS-reportable events. BAs whose ACE is extremely negative for other reasons would be reluctant to
deploy their contingency reserves because the timer would start ticking on the “available hours” clock. The second
unintended consequence for those BAs that don’t withhold contingency reserves for non-DCS events is that they will be
obliged to increase the amount of contingency reserves they carry so they always have more contingency reserves than
their MSSC. This will increase costs to our customers without a demonstrated need. DCS performance in North America
has been stellar compared to what was considered adequate performance under Policy 1. The standard provides no clear
definition on how contingency reserves are measured. Does it include all generation headroom available in 10 minutes? In
15 minutes? What about resources that are also providing AGC? Does their instantaneous headroom count? Are load
resources available in 15 minutes or 10 minutes counted? What about demand response resources that aren’t directly
measured? Finally, are the hours referenced in the standard clock-hours, any contiguous 60 minute period, or the total
minutes in a quarter divided by 60? Proposed Solutions We recommend the two core requirements in the existing BAL-002
be retained with modification: R1. Except when experiencing an Energy Emergency Alert Level 2 or Level 3, a Balancing
Authority or Reserve Sharing Group experiencing a Reportable Event less than or equal to its MSSC shall activate sufficient
Contingency Reserve to comply with the DCS. Events > than MSSC are reported, but do not factor into the compliance
calculation. R2. Except when experiencing an Energy Emergency Alert Level 2 or Level 3, a Balancing Authority or Reserve
Sharing Group experiencing a Reportable Event less than or equal to its MSSC shall replenish its reserves within 105
minutes of the onset of the Reportable Event. We would be OK with an addition requirement that asks the BA to perform
an assessment of its next day and real time reserve targets and the basis of its MSSC and that the BA provide this
assessment to its Operators and its Reliability Coordinator. The assessment should be done each calendar year or within a
month following an event > MSSC. To provide clarity, the compliance section of the standard should describe the reporting
approach for events > MSSC. The “Reserve Guidelines” document should be expanded to explain that BAs are expected to
make best efforts to recover from events > MSSC, but that transmission security takes precedence. Either the Reserve
Guidelines document, the compliance section of the standard, or an appendix to the standard should include the reporting
form for DCS. Alternatively, the drafting team could create the report in spreadsheet form. The reporting form should be
similar to what is used today. The form should include the basis of the MSSC. The sizes of the Reportable Events for the
Interconnections proposed by the drafting team are acceptable and meet the intent of one of the 693 directives. We
believe it is acceptable to put something in the compliance section of the standard that notes if the same event > than
MSSC occurs within 3 years, the BA should be held to the DCS for that contingency until it demonstrates the triggering
mechanism has been mitigated. We agree with the current direction of the team to address the 693 directive to develop a
“continent-wide contingency reserve policy” via the “Reserve Guidelines” document. Beyond what is mentioned above, the

document should provide guidance on how the BA assesses the necessary amount of reserves as well as provide simple
definitions of the different types of reserves (in particular for this standard, contingency reserves and replacement
reserves). Once these terms are defined and commented on by the Industry in the document, NERC should add these
types of reserves to “Attachment 1-TOP-005 Electric System Reliability Data” with the expectation in the policy that
Reliability Coordinators collect this information in real time for use in the EEA process. We believe there would be
significant reliability value in giving RCs visibility of the current state of Contingency Reserves (something callable in 10
minutes, fully deployed in 15 minutes and sustainable for at least 90 minutes) and Replacement Reserves (something
callable in 90 minutes and sustainable for say 4 hours). This would directly contribute to reliability by providing objective
information to BAs and RCs in managing Energy Emergency Alerts.
Individual
Richard Vine
California Independent System Operator
The proposed standard would require the California ISO to treat a loss of MW output greater than or equal to 500 MW as a
Reportable Balancing Contingency Event resulting in dispatch of reserves to meet DCS recovery time limits. Currently, the
ISO is only required to dispatch reserves for DCS events greater than 80 percent of the Most Severe Single Contingency,
or about 900 MW. There does not appear to be any technical justification for this significant reduction in reporting/action
threshold which will result in the unnecessary deployment of contingency reserves on a more frequent basis.
Group
Southern Company: Alabama Power Company; Georgia Power Company; Gulf Power Company; Mississippi Power
Company; Southern Company Generation; Southern Company Generation and Energy Marketing
Pamela Hunter
Agree
SERC OC Standards Review Group
Group
Bureau of Reclamation
Erika Doot
The Bureau of Reclamation supports the proposed standard.
Group
Bonneville Power Administration
Jamison Dye
BPA concurs with the current draft of BAL-002-2 with no comments or concerns.
Individual
Kathleen Goodman
ISO New England Inc.
Agree
IRC SRC

Standards Announcement

Project 2010-14.1 Balancing Authority Reliability-based
Controls: Reserves (BAL-002-2)
An Additional Ballot and Non-Binding Poll is now open through September 16, 2013
Now Available

An additional ballot for BAL-002-2- Contingency Reserve for Recovery from a Balancing
Contingency Event and non-binding poll of the associated Violation Risk Factors (VRFs) and
Violation Severity Levels (VSLs) is now open through 8 p.m. Eastern on Monday, September 16,
2013.
Background information for this project can be found on the project page.
Instructions for Balloting
Members of the ballot pools associated with this project may log in and submit their vote for the
standard and non-binding poll of the associated VRFs and VSLs by clicking here.
As a reminder, this ballot is being conducted under the revised Standard Processes Manual, which
requires all negative votes to have an associated comment submitted (or an indication of support
of another entity’s comments). Please see NERC’s announcement regarding the balloting software
updates and the guidance document, which explains how to cast your ballot and note if you’ve
made a comment in the online comment form or support another entity’s comment.
Next Steps

The ballot results will be announced and posted on the project page. The drafting team will consider all
comments received during the formal comment period and, if needed, make revisions to the standard.
If the comments do not show the need for significant revisions, the standard will proceed to a final
ballot.
Standards Development Process

The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.

North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Announcement – Project 2010-14.1 BAL-002-2

2

Standards Announcement

Project 2010-14.1 Balancing Authority Reliability-based
Controls: Reserves
BAL-002-2
Additional Ballot and Non-Binding Poll Results
Now Available

An additional ballot for BAL-002-2- Contingency Reserve for Recovery from a Balancing
Contingency Event and non-binding poll of the associated Violation Risk Factors (VRFs) and
Violation Severity Levels (VSLs) concluded at through 8 p.m. Eastern on Monday, September 16,
2013.
Voting statistics for the additional ballot are listed below, and the Ballot Results page provides a link to
the detailed results. This standard achieved a quorum but did not receive sufficient affirmative votes
for approval.

Approval

Non-binding Poll Results

Quorum: 76.15%

Quorum: 75.69%

Approval: 58.23%

Supportive Opinions: 59.66%

Background information for this project can be found on the project page.
Next Steps

The drafting team will consider all comments received during the formal comment period and, if
needed, make revisions to the standard. The standard will then proceed to an additional comment
period and ballot.
Standards Development Process

The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.

For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Announcement – Project 2010-14.1 BAL-002-2

2

NERC Standards
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https://standards.nerc.net/BallotResults.aspx?BallotGUID=0a26561f-2218-42b6-bbc4-6853d6ac882a[9/19/2013 12:32:23 PM]


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&RQVROLGDWHG(GLVRQ&RRI1HZ MSSC. This will allow the Drafting
Team to use simpler wording for the requirements. Footnote 1--The IROL standards still require
operators to take whatever action is necessary to prevent cascading with the next contingency, to
include shedding load or redispatch. The new BAL-001 standard will require the Balancing Authority
to take action within 30 minutes to get frequency back within acceptable bounds. The Energy
Emergency Alert process still exists to address any reserve shortfall. Comments on R1 Events >
MSSC. As noted earlier, events where the capacity (not MW) loss > MSSC should not be evaluated
under this standard. Even if the MW loss was within the reporting threshold, the BA would have lost
the reserves it needed to assist the recovery. We agree that events > MSSC can be reported on a
different sheet on the reporting form, but there should not be an associated measure. The report
should capture the time, unit, power, and capacity loss. Multiple lines on the report would be needed
for each event series. When multiple contingencies occur, we want the operator to assess their
actions based on impact on the transmission system rather than achieving a zero ACE. As noted
earlier, there are protective backstops in place (IROL, BAAL, EEA). Change from Quarterly Metric.
DCS performance has always been calculated and reported on a quarterly basis. This is similar to
CPS1 and CPS2 whose performance is based on annual and monthly calculations. While we
understand that this change was a directive in Order No. 693, the Drafting Team has the option to
point out the rationale why the directive will have unintended consequences. We believe this single
event metric will lead to changes in how Reserve Sharing Groups select events, only reporting those
very large events rather than allowing members to call for reserves for smaller contingencies. This is
a step backward from a reliability perspective. Should the Drafting Team decide to not retain the
quarterly metric, we strongly recommend staying with a quarterly report form with each event listed
separately to reduce the administrative overhead. Comments on R2: As proposed we believe this
requirement will have significant negative unintended consequences. Reserves are an inventory
intended to be used when there is a reliability need. The original Policy 1 listed multiple reasons for

carrying operating reserves (errors in forecasting, generation and transmission equipment
unavailability, number and size of generating units, system equipment forced outage rates,
maintenance schedules, regulating requirements, and Regional and system load diversity). The first
unintended consequence is that BAs are discouraged from deploying their contingency reserves
except for DCS-reportable events. There will be a reluctance to deploy reserves if it will take the
balance to less than MSSC. We may also experience repeated frequency swells at the start and end
of each hour as BAs try to “bank” average reserves or make up for earlier deficiencies early in the
hour. The second unintended consequence for those BAs that don’t withhold contingency reserves
for non-DCS events is that they will be obliged to increase the amount of contingency reserves they
carry so they always have more contingency reserves than their MSSC. This will increase costs to
our customers without a demonstrated need. What is the driver for this requirement? It is not within
the scope of the Drafting Team’s SAR, nor was it directed in Order No. 693. DCS performance in
North America has been stellar compared to what was considered adequate performance under
Policy 1. One approach is to include a commodity measure that fits within the context of the original
DCS and would not discourage the operator from deploying reserves for non-reportable events. For
example, consider a medium size BA that has heavier than expected loads due to rain/darkness and
associated wet coal conditions at one or more of its plants: • The operator starts falling behind on
the load pickup, but deploys most of its on-line reserves to keep up with load. • Because of the wet
coal, there are some limitations on the units that further reduce its reserves. • The operator finds
out 10 minutes after the hour that they were < MSSC on reserves. • The operator initiates action to
replenish reserves, but since s/he is already well into the hour, s/he won’t be able to fully recover
them for 90 minutes (same as the current standard expects). This means the operator did the right
thing, but had 3 hours where reserves were < MSSC. As long as the operator had a plan and could
withstand the next contingency, there is no negative impact on reliability. Finally, as we noted in the
informal posting of this standard, the team has not provided a simple, clear definition on how
contingency reserves are measured as prosed under R2. The definition should be something that can
be implemented in an EMS. Does it include all generation headroom available in 10 minutes? In 15
minutes? Do regulating resources with headroom count as contingency reserves? Are load resources
available in 15 minutes or 10 minutes counted? What about demand response resources that aren’t
directly measured? Proposed Solutions: As noted earlier, we recommend including exclusions that
will allow simplification of the requirements. The two requirements could then be simplified as
follows: R1. The Responsible Entity experiencing a Reportable Balancing Contingency Event shall,
within the Contingency Event Recovery Period, return its ACE to at least: • Zero, if pre-contingency
ACE was positive or equal to zero. • Pre-contingency ACE value, if pre-contingency ACE was
negative. We offer two suggestions for R2: R2. The Responsible Entity experiencing a Reportable
Event shall replenish its Contingency Reserves within 105 minutes of the onset of the Reportable
Event. Alternatively, it would be consistent with the current standard to have: R2. The Responsible
Entity’s hourly average Contingency Reserves shall not be < its MSSC for more than three
consecutive clock hours. In addition regarding R2, the removal of the “five hours exemption” in R2 is
not an enhancement since it could encourage some BAs to avoid activating their contingency
reserves in some situations to avoid being non-compliant. For example, if there is an important unforecasted increase of demand, an IROL limit violation or a voltage problem, the activation of
contingency reserve could probably most of the time resolve the problem. With the new proposition
it would lead to a non-compliance on R2 of BAL-002-2. Because of this the 5 hours exemption
should be considered to be kept for reliability reasons. Considering the Quebec Interconnection,
there are contingencies that occur where generation and load are lost at the same time. There are
contingencies where 1900 MW of generation is lost and 1600 MW of DC converters at the same time,
the net loss for the BA/Interconnection being 300 MW. The net loss causes a small ACE change and
is under the Reportable Balancing Contingency Event threshold. In addition, the 1600 MW of DC
converter loss would probably be reported by another entity as a DCS due to a loss of an import. For
this reason, suggest that the Balancing Contingency Event and the Reportable Balancing
Contingency Event definitions be revised to include the concept of net loss for the BA instead of only
the generator MW output. As for the Reportable Balancing Contingency Event threshold, the 500 MW
threshold for the Quebec Interconnection should be reconsidered. As for now, the actual threshold
set at 80% of MSSC which corresponds generally around 800 MW already traps events that are
significant for the Interconnection and truly measure events where contingency reserve is being
deployed by operator actions. A too low threshold might capture events that are recovered with
frequency response and AGC action, which are deployed quickly after the event since Quebec is in a

single BA Interconnection. The proposed threshold in the draft would augment the reporting needs
without any improvement in measuring contingency reserve deployment.
Individual
Thomas Foltz
American Electric Power
Yes
AEP questions if this new version is an improvement over the current BAL-002-1. There are many
more terms that are cross referenced and it will become a risk that operators will struggle to tie all
the pieces together. This proposed standard, while it might be more flexible in some regards, might
cause unnecessary confusion. AEP recommends changing the definition for Balancing Contingency
Event to the following: “Any single event described below, or any series of such otherwise single
events, with each separated from the next by less than one minute and, that causes a significant
change to the responsible entity’s ACE caused by 1. Sudden loss of supply (generation or import),
not including controlled shutdown of a unit. …or … 2. Restoration of a load” Reserve Sharing Group
Reporting ACE: the addition of the “at the time of measurement” is now stated twice in the same
sentence. We believe one of the references should be removed. R1 1.1, 1.2, and 1.3: The content
provides guidance and exception information, but includes no obligatory language. As a result, these
sub requirements should instead be moved into either footnotes or bullet points. R2 is very difficult
to follow with all of the exceptions. Furthermore, it would be better to start with the expected
obligation and have the exceptions to the rule follow in the sentence or maybe in a footnote. We do
support some amount of a “grace period” during these events, however, what is the reliability basis
for the 5 hour duration?
Individual
Gerald G Fattinger
Consumers Energy
Yes
a) The definition of Balancing Contingency Event is long and cumbersome. Any loss of generation or
import no matter how minor is considered a Balancing Contingency Event. The true trigger for an
Event should be a change in the ACE of a specified amount of percentage. The cause of the deviation
(other than meter or telemetry error) is immaterial and has no real impact on actions taken. b)
Having a definition of a Contingency Event and a Reportable Contingency Event is piling on. One
definition is all that is required. c) Applicability to a Reliability Standard should not be dependent on
an Event. This is either applicable to a BA or RSG or it is not. The fact that the measurement only
happens when a Recordable Event occurs is irrelevant to the applicability. d) This standard is difficult
to read through and overly complicated. e) Definitions in BAL-002-1 are clear and succinct. They
should remain for this standard.
Individual
Michael Falvo
Independent Electricity System Operator
Yes
We continue to disagree with defining new terms and move them to the NERC Glossary when the
standard is approved. Many of these terms are used exclusively in this standard only, and as such,
should be kept within the standard and not be moved to the NERC Glossary. Moving these terms to
the NERC Glossary creates unnecessary maintenance burden, and may create a conflict with similar
terms used in other NERC documents. A Balancing Contingency Event is vaguely defined as a
“Sudden loss of generation...” or “sudden decline in ACE...”. The word sudden is imprecise, and
should be clarified. We suggest that the standard be clearer about defining the start time for a
Reportable BCE. We support definitions like that used in NPCC Directory 5 section 5.17 where we say
that the start of an event has occurred when a specific X amount of MWs are lost in a specific Y
amount of time. Therefore, we suggest that the drafting team add precision in determining minute
T+0 for an event by adding the following sentence (or something like it) to the Reportable BCE

definition: Following the resource failure, the Reportable BCE starting time is defined as the first
chronological rolling one minute interval that meets the reduction in resource output(s) criteria
stated herein.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
Agree
SERC OC Review Group
Individual
Kayleigh Wilkerson
Lincoln Electric System
Yes
Although supportive of the drafting team's efforts to improve BAL-002, LES is concerned with the
proposed definitions of Most Severe Single Contingency (MSSC) and Reportable Balancing
Contingency Event. As drafted, the definition of MSSC does not clearly state whether or not the
Reserve Sharing Group (RSG), or the Balancing Authority not in a RSG, can define whether or not
the MSSC is operationally defined or defined in advance. Additionally, the definition of Reportable
Balancing Contingency Event is confusing as proposed. Recommend the drafting team consider
incorporating a formula within the definition to provide additional clarity.
Individual
Kathleen Goodman
ISO New England Inc.
We believe the term “sudden” should be defined as a “step change.” Does “imbalance between
generation and load on the Interconnection” imply causing an imbalance beyond the BA or RSG
boundary? Could that mean that associated transaction curtailments factor into the overall
contingency size? “Begins to decline” in the definition of Contingency Event Recovery Period should
be “Begins to decline unexpectedly.” “Averaged over each Clock Hour” should be averaged over
three to five clock hours so as to be manageable practically from an operational perspective.
Suggest modifying R2, as: “R2. Except during the Responsible Entity’s Contingency Event Recovery
Period and the Responsible Entity’s Contingency Reserve Restoration Period, or during an Energy
Emergency Alert Level 2 or 3 for the Responsible Entity, the Responsible Entity shall maintain an
amount of Contingency Reserve, averaged over a rolling (3-5) Clock Hour interval at least equal to
the average of the Most Severe Single minus the average Area Control Area over the same interval.”
Generally speaking, the requirement to maintain an amount of Contingency Reserve at least equal to
its Most Severe Single Contingency may, in fact, reduce reliability. As we read it, the only two
reasons that these reserves may go below MSCC are: during an EEA 2 or 3; or during the
Contingency Reserve Restoration Period. Therefore, in order to maintain compliance, one might not
deploy reserves for events such as a missed load forecast, opting instead to “drag” on the
Interconnection. This seems counterintuitive to a reliability standard. Requirement 1.2 does not
provide clarity as to the applicable EEA 2/3 trigger. Can the Contingency Event itself trigger the
EEA? Assuming it cannot, alternate language may be: “1.2. Requirement R1 (in its entirety) does
not apply when the Responsible Entity experiencing a Reportable Balancing Contingency Event is
experiencing an Energy Emergency Alert Level 2 or Level 3 at the time that the Reportable Balancing
Contingency Event occurs.”
Individual
Marie Knox
MISO
Yes
We appreciate the efforts of the drafting team as well as the opportunity to comment. Our primary
concern is that this project is taking a step back from performance-based standard and moving

toward a zero-defect commodity obligation. The intent of the original Policy 1 DCS was to prepare
for contingencies of any type and restore balance after they occur. It was understood that multiple
events and unforeseen situations arose. This is why performance was measured over many events
over a quarter. What is now proposed will likely lead to several negative unintended consequences
(added cost for no identified need, wider intra-hour frequency variation to as BAs change dispatch to
always have a given hourly average, fewer reportable events as each event is singularly
sanctionable, and a likely step increase in the calling of EEAs 2 and 3). The reality is most of the
Order No. 693 items the team is attempting to address have already been more effectively covered
by BAL-001-2 R2 (commonly called BAAL). Simplifying the Verbiage in the Standard While we agree
with the drafting team’s goal to better define when the requirements apply, the wording makes it
difficult to follow the true meaning of the requirements. We get differing opinions among our peers
on what the standard is saying. The current standards use several different approaches to say when
a requirement applies and when it doesn’t (search on “exemptions”, “exclusions”, or “does not
apply” to find examples). We suggest the following to make the requirements simpler. First, we
recommend adding an “Exclusions” section under “Applicability”. Exclusions: • R1 and R2 do not
apply during EEA 2 or EEA 3. • R1 does not apply for multiple non-simultaneous events [Rationale:
These events are adequately addressed by IROL, BAAL and EEA requirements ] • R1 does not apply
for single or simultaneous events where the capacity loss is > MSSC. This will allow the drafting
team to use simpler wording for the requirements. Comments on R1 Events > MSSC. As noted
earlier, events where the capacity (not MW) loss > MSSC should not be evaluated under this
standard. Even if the MW loss was within the reporting threshold, the BA would have lost the
reserves it needed to assist the recovery. We agree that events > MSSC can be reported on a
different sheet on the reporting form, but there should not be an associated measure. The report
should capture the time, unit, power, and capacity loss. Multiple lines on the report would be needed
for each event series. When multi-contingent events occur, we want thoughtful and measured action
on the part of the operator. In most cases the first priority is to assess their actions based on impact
on the transmission system rather than achieving a zero ACE. As noted earlier, there are protective
backstops in place (IROL, BAAL, EEA). Change from Quarterly Metric. DCS performance has always
been calculated and reported on a quarterly basis. This is similar to CPS1 and CPS2 whose
performance is based on annual and monthly calculations. While we understand that this change
was a directive in Order No. 693, the drafting team has the option to point out the rationale why the
directive will have unintended consequences. We believe this single event metric will lead to changes
in how Reserve Sharing Groups select events, only reporting those very large events rather than
allowing members to call for reserves for smaller contingencies. This is a step backward from a
reliability perspective. Should the drafting team reject the comment to retain the quarterly metric,
we strongly recommend staying with a quarterly report form with each event listed separately to
reduce the administrative overhead. Comments on R2 As proposed we believe this requirement will
have significant negative unintended consequences. Reserves are an inventory intended to be used
when there is a reliability need. The original Policy 1 listed multiple reasons for carrying operating
reserves (errors in forecasting, generation and transmission equipment unavailability, number and
size of generating units, system equipment forced outage rates, maintenance schedules, regulating
requirements, and Regional and system load diversity). The first unintended consequence is that
BAs are discouraged from deploying their contingency reserves except for DCS-reportable events.
There will be a reluctance to deploy reserves if it will take the balance to less than MSSC. We may
also experience repeated frequency swells at the start and end of each hour as BAs try to “bank”
average reserves or make up for earlier deficiencies early in the hour. The second unintended
consequence for those BAs that don’t withhold contingency reserves for non-DCS events is that they
will be obliged to increase the amount of contingency reserves they carry so they always have more
contingency reserves than their MSSC. This will increase costs to our customers without a
demonstrated need. We could offer one approach to including a commodity measure that fits within
the context of the original DCS and would not discourage the operator from deploying reserves for
non-reportable events. A scenario would help explain this suggestion. Consider a medium size BA
that has heavier than expected loads due to rain/darkness and associated wet coal conditions at one
or more of its plants: • The operator starts falling behind on the load pickup, but deploys most of its
on-line reserves to keep up with load. • Because of the wet coal, there are some limitations on the
units that further reduce its reserves. • The operator finds out 10 minutes after the hour that they
were < MSSC on reserves. • The operator initiates action to replenish reserves, but since s/he is
already well into the hour, s/he won’t be able to fully recover them for 90 minutes (same as the

current standard expects). This means the operator did the right thing, but had 3 hours where
reserves were < MSSC. As long as the operator had a plan and could withstand the next
contingency, there is no negative impact on reliability. Finally, as we noted in the informal posting of
this standard, the team has not provided a simple, clear definition on how contingency reserves are
measured as prosed under R2. The definition should be something that can be implemented in an
EMS. Does it include all generation headroom available in 10 minutes? In 15 minutes? Do regulating
resources with headroom count as contingency reserves? Are load resources available in 15 minutes
or 10 minutes counted? What about demand response resources that aren’t directly measured?
Proposed Solutions for the Standard As noted earlier, we recommend including an “Exclusions”
subsection under “Applicability” that will allow simplification of the requirements. The two
requirements can then be simplified as follows: R1. The Responsible Entity experiencing a
Reportable Balancing Contingency Event shall, within the Contingency Event Recovery Period, return
its ACE to at least: • Zero, if pre-contingency ACE was positive or equal to zero. • Pre-contingency
ACE value, if pre-contingency ACE was negative. We offer two suggestions for R2: R2. The
Responsible Entity experiencing a Reportable Event shall replenish its Contingency Reserves within
105 minutes of the onset of the Reportable Event. Alternatively, it would be consistent with the
current standard to have R2. The Responsible Entity’s hourly average Contingency Reserves shall
not be < its MSSC for more than three consecutive clock hours. Other Recommendations to Support
Reliability We again suggest an informed approach to first provide simple definitions of the different
types of reserves (in particular for this standard, contingency reserves and replacement reserves).
Once these terms are defined and commented on by the Industry, NERC should add these types of
reserves to “Attachment 1-TOP-005 Electric System Reliability Data” with the expectation that
Reliability Coordinators collect this information in real time for use in the EEA process. We believe
there would be significant reliability value in giving RCs visibility of the current state of Contingency
Reserves (something callable in 10 minutes, fully deployed in 15 minutes and sustainable for at least
90 minutes) and Replacement Reserves (something callable in 90 minutes and sustainable for say 4
hours). This would directly contribute to reliability by providing objective information to BAs and RCs
in managing Energy Emergency Alerts.
Individual
Barbara Kedrowski
Wisconsin Electric Power Co.
Agree
MISO
Group
Duke Energy
Michael Lowman
Yes
(1) Duke Energy believes that the existing definition of a Balancing Contingency Event is redundant
and imprecise. We recommend that the definition be revised as follows: Balancing Contingency
Event: Any single event described in Subsections (A) or (B) below, or any series of such otherwise
single events, with each separated from the next by less than one minute. A. Sudden loss of
generation or import due to Unit tripping or the sudden unplanned outage of transmission Facility
that causes an unexpected change to the responsible entity’s ACE; B. Sudden restoration of a load
that was used as a resource that causes an unexpected change to the responsible entity’s ACE. Duke
Energy has previously commented that Item B of the existing Balancing Contingency Event definition
should be removed because it is already covered under Item A. The modification of Item (A) to
include “Sudden loss of generation or import…” makes it clear and explicit that Item (A) includes the
loss of an import due to either unit trip or the sudden unplanned outage of a transmission facility. In
addition, there is no need to cover the loss of Interconnection Facilities in the existing section
(A)(a)(ii) because Interconnection Facilities are included in transmission Facilities and would also
necessarily result in a unit trip, and both of these circumstances are covered elsewhere in the
definition. The existing definition also refers to “unplanned outage of transmission Facility” in section
(A)(a)(ii) versus the reference to “forced outage of transmission equipment” in section (B). Duke
believes that describing transmission outages using different terms within the same definition will
result in confusion and differing interpretations of the meaning of the definition. The proposed

elimination of section (B) resolves this issue as well. (2) Regarding Requirement 2, Duke Energy still
maintains that this Standard should remain a results-based Standard and not burden responsible
entities with the tracking of reserves maintained. The existence of a requirement such as R2 will
result in inefficient utilization of resources, increased costs, inaccurate representation of resource
capability, and other negative consequences with no benefit to reliability. (3) Duke Energy suggests
combining and rewording sub-requirement 1.2 and 1.3 as follows: “R1.2 Requirement R1 (in its
entirety) does not apply to the Responsible Entity if any of the following occurs: 1.2.1 The
Responsible Entity experiencing a Reportable Balancing Contingency Event is also experiencing an
Energy Emergency Alert Level 2 or Level 3. 1.2.2 The Responsible Entity experiencing a Balancing
Contingency Event has an additional event causing the sum of the aggregated events to exceed its
MSSC within 15 minutes of the original BCE. 1.2.3 A subsequent BCE that occurs beyond the 15
minute period but is within 105 minutes of the first Balancing Contingency Event provided that the
sum of the BCEs exceeded the Responsible Entity’s Most Severe Single Contingency.” We feel that
this wording describes more clearly those instances where a Responsible Entity is not required to
report the event as described in Requirement 1.
Group
IRC Standards Review Committee
Terry Bilke
Yes
Background and General Comments We appreciate the efforts of the drafting team as well as the
opportunity to comment. We agree with the drafting team’s goal to better define when the
requirements apply. The approach taken makes it difficult to follow the true meaning of the
requirements. We get differing opinions among our peers on what the standard is saying. There are
different approaches used in the standards to say when a requirement applies and when it doesn’t
(“exemptions”, “exclusions”, or “does not apply”). We suggest an alternative approach to make the
requirements simpler. We recommend adding an “Exclusions” section under “Applicability”.
Exclusions: • R1 and R2 do not apply during EEA 2 or EEA 3. • R1 does not apply for multiple nonsimultaneous events [Rationale: These events are adequately addressed by IROL, BAAL and EEA
requirements ] • R1 does not apply for single or simultaneous events where the capacity loss is >
MSSC. This will allow the drafting team to use simpler wording for the requirements. Comments on
R1 Events > MSSC. As noted earlier, events where the capacity (not solely MW) loss > MSSC should
not be evaluated under this standard. Even if the MW loss was within the reporting threshold, the BA
would have lost the reserves it needed to assist the recovery. We agree that events > MSSC can be
reported on a different sheet on the reporting form, but there should not be an associated measure.
The report should capture the time, unit, power, and capacity loss. Multiple lines on the report would
be needed for each event series. When multi-contingent events occur, we want thoughtful action on
the part of the operator. In most cases they should assess their actions first based on impact on the
transmission system rather than achieving a zero ACE. As noted earlier, there are protective
backstops in place (IROL, BAAL, EEA). Change from Quarterly Metric. DCS performance has always
been calculated and reported on a quarterly basis. This is similar to CPS1 and CPS2 whose
performance is based on annual and monthly calculations. While we understand that this change
was a directive in Order No. 693, the drafting team has the option to point out the rationale why the
directive will have unintended consequences. We believe this single event metric will lead to changes
in how Reserve Sharing Groups select events, only reporting those very large events rather than
allowing members to call for reserves for smaller contingencies. This is a step backward from a
reliability perspective. Should the drafting team reject the comment to retain the quarterly metric,
we strongly recommend staying with a quarterly report form with each event listed separately to
reduce the administrative overhead. Comments on R2 As proposed we believe this requirement will
have significant negative unintended consequences. Reserves are an inventory intended to be used
when there is a reliability need. The original Policy 1 listed multiple reasons for carrying operating
reserves (errors in forecasting, generation and transmission equipment unavailability, number and
size of generating units, system equipment forced outage rates, maintenance schedules, regulating
requirements, and Regional and system load diversity). The first unintended consequence is that
BAs are discouraged from deploying their contingency reserves except for DCS-reportable events.
There will be a reluctance to deploy reserves if it will take the balance to less than MSSC. We may
also experience repeated frequency swells at the start and end of each hour as BAs try to “bank”

average reserves or make up for earlier deficiencies early in the hour. The second unintended
consequence for those BAs that don’t withhold contingency reserves for non-DCS events is that they
will be obliged to increase the amount of contingency reserves they carry so they always have more
contingency reserves than their MSSC. This will increase costs to our customers without a
demonstrated need. We struggle to understand the driver for this requirement. It is not within the
scope of the drafting team’s SAR, nor was it directed in Order No. 693. DCS performance in North
America has been stellar compared to what was considered adequate performance under Policy 1.
We could offer one approach to including a commodity measure that fits within the context of the
original DCS and would not discourage the operator from deploying reserves for non-reportable
events. A scenario would help explain this suggestion. Consider a medium size BA that has heavier
than expected loads due to rain/darkness and associated wet coal conditions at one or more of its
plants: • The operator starts falling behind on the load pickup, but deploys most of its on-line
reserves to keep up with load. • Because of the wet coal, there are some limitations on the units
that further reduce its reserves. • The operator finds out 10 minutes after the hour that they were <
MSSC on reserves for the previous hour. • The operator initiates action to replenish reserves, but
since s/he is already well into the hour, s/he won’t be able to fully recover them for 90 minutes
(same as the current standard expects). This means the operator did the right thing, but had 3
hours where reserves were < MSSC. As long as the operator had a plan and could withstand the
next contingency, there is no negative impact on reliability. Finally, as we noted in the informal
posting of this standard, the team has not provided a simple, clear definition on how contingency
reserves are measured as prosed under R2. The definition should be something that can be
implemented in an EMS. Does it include all generation headroom available in 10 minutes? In 15
minutes? Do regulating resources with headroom count as contingency reserves? Are load resources
available in 15 minutes or 10 minutes counted? What about demand response resources that aren’t
directly measured? Proposed Solutions As noted earlier, we recommend including an “Exclusions”
subsection under “Applicability” that will allow simplification of the requirements. The two
requirements can then be simplified as follows: R1. The Responsible Entity experiencing a
Reportable Balancing Contingency Event shall, within the Contingency Event Recovery Period, return
its ACE to at least: • Zero, if pre-contingency ACE was positive or equal to zero. • Pre-contingency
ACE value, if pre-contingency ACE was negative. We offer two suggestions for R2: R2. The
Responsible Entity experiencing a Reportable Event shall replenish its Contingency Reserves within
105 minutes of the onset of the Reportable Event. Alternatively, it would be consistent with the
current standard to have R2. The Responsible Entity’s hourly average Contingency Reserves shall
not be < its MSSC for more than three consecutive clock hours.
Individual
Anthony Jablonski
ReliabilityFirst
Yes
ReliabilityFirst abstains and offers the following comments for consideration: 1. Requirement R1,
Part 1.1 - ReliabilityFirst suggests using the word “shall” instead of “will” to make mandatory the use
of the noted CR Form 1. Also, the SDT responses to the last comment period indicated that the CR
Form 1 would be included as an attachment to the standard, but after review the form has yet to be
attached. ReliabilityFirst recommends attaching it to the standards along with the following change
for consideration: “All Reportable Balancing Contingency Events [shall] be documented using
Attachment 1 - CR Form 1.” 2. Requirement R1, Part 1.3 - For consistency with the second sentence
of Requirement R1, Part 1.3, ReliabilityFirst recommends using the word “shall” in the first sentence.
ReliabilityFirst recommends the following for consideration: “Requirement R1 (in its entirety) [shall]
not apply…” 3. Requirement R1, Part 1.3 - ReliabilityFirst requests the rationale behind using the
105 minute timeframe referenced in the second sentence of Requirement R1, Part 1.3.
ReliabilityFirst is trying to understand if there is any technical merit behind this timeframe or if it is
solely based on SDT experience. 4. Measure M2 - The newly included second paragraph within
Measure M2 reads more as an exception to the requirement and does not belong as a measure. It
appears to be guidance to an auditor and should more appropriately be placed in an RSAW.
Furthermore, ReliabilityFirst does not want to encourage missing data as reason for not performing
the calculation and believes any or as many valid samples of the Contingency Reserve should be
included in the clock hour and should not be excluded from the evaluation. ReliabilityFirst

recommends completely removing the second paragraph within Measure M2 from the standard. 5.
VSL Requirement R1 - There is no VSL associated with an entity failing to document Reportable
Balancing Contingency Events using CR Form 1 per Requirement R1, Part 1.1. ReliabilityFirst
recommends the following for an additional Moderate VSL: “The Responsible Entity failed to
document Reportable Balancing Contingency Events using CR Form 1 per Requirement R1, Part 1.1”
Group
Seattle City Light
Paul Haase
Yes
R2 cannot be implemented or audited as written. There are two flaws. The first flaw is that R2
requires entities to carry Contingency Reserves equal to its MSSC. The problem is that Contingency
Reserves, as specified in the draft, are "averaged over each clock hour" whereas MSSC is defined as
the MW output of the largest source AT THE TIME OF AN EVENT; i.e. the requirement demands the
logical impossibility of measuring an hourly average against an instantaneous value. Absent an
event, the comparison cannot be made. The second flaw is that by defining Contingency Reserves as
an hourly average, entities are left chasing a target that is not defined until an hour is over. It is
possible to employ a conservative reserve profile for the first half of an hour and then ramp up as
necessary to meet the target, as it become better known. Employed broadly, this approach could
leave the BES short of reserves during the first half of each hour, and does not improve reliability.
Seattle recommends that the draft be changed to require an instantaneous value of Contingency
Reserves to address both of these flaws. Seattle recognizes the effort of the Standard Drafting team
to afford flexibility in meeting Contingency Reserve requirements, but finds the approach as written
to be unworkable. Although we ballot in support of the present draft, to indicate that it represents an
improvement over existing Standard, Seattle will vote NO for future drafts that do not address the
flaws in R2 as presently written.
Group
Southern Company: Southern CompanyServices, Inc.; Alabama Power Company; Georgia Power
Company; Gulf Power Company; Mississippi Power Company; Southern Company Generation;
Southern Company Generation and Energy Marketing
Marcus Pelt
Yes
Southern disagrees with removing the additional 5 hours in a given calendar quarter and the
changes made to the VSLs for R2. The industry and NERC are trying to move away from the “zero
defect” concept, and the changes to this draft of the standard reintroduce the “zero defect”
concerns. As currently drafted, an entity could have one clock hour where the average Contingency
Reserve is 99% of the MSSC and be found non-compliant under R2. Southern recommends
incorporating a reasonable tolerance period into R2 so that an entity is not in violation in this
example.
Individual
Howard F. Illian
Energy Mark, Inc.
No
I have no issues with this draft and support its implementation.
Individual
Oliver Burke
Entergy Services, Inc.
Yes

Entergy does not support the use of an hourly metric as it will force unnecessary, expensive, and
counterproductive activities to meet a compliance requirement. NERC SDT should consider longer
time increment.
Individual
Silvia Parada Mitchell
NextEra Energy
Yes
Section - Definitions of Terms Used in Standard Balancing Contingency Event: Any single event
described in Subsections (A), (B), or (C) below, or any series of such otherwise single events, with
each separated from the next by less than one minute. B. Sudden loss of an import, due to forced
outage of transmission equipment that causes an unexpected imbalance between generation and
load on the Interconnection. NextEra comments: There are other mechanisms to handle sudden loss
of import and sudden unplanned outage, this should not be in this standard. The IROL standards
require operators to take action to prevent reliability issues including redispatch and shed load.
Having FRSG groups activate Contingency Reserves could have unintended consequences.
Examples: In the event that multiple BAs are being affected by the reduction of the import; if all BAs
call for reserves the overall recovery will be delayed since the BAs will be importing and exporting
power. If TLR is used to curtail import due to reliability issue and the transaction affected was
between two or more members of the same FRSG group, the call for reserves will negate the loading
relief of the TLR. C. Sudden restoration of a load that was used as a resource that causes an
unexpected change to the responsible entity’s ACE. NextEra comments: This should not be part of
BAL-002. Restoration of load should be done in a controlled manner and if a BA does not have
sufficient generation to restore firm load, then the EEA process should be followed.
Individual
Shirley Mayadewi
Manitoba Hydro
Yes
(1) Reportable Balancing Contingency Event, D2 - to improve clarity, we suggest removing “equal
to”. We realize that this will result in some MW difference. For example: Reportable Balancing
Contingency Event: Any Balancing Contingency Event resulting in a loss of MW output less than or
equal to the Most Severe Single Contingency, and greater than or equal to the lesser amount of: (i)
80% of the Most Severe Single Contingency, or (ii) the amount listed below for the applicable
Interconnection, and occurring within a one-minute interval of the initial sudden decline in ACE
based on EMS scan rate data. Prior to any given calendar quarter, the 80% threshold may be
reduced by the responsible entity upon written notification to the Regional Entity. So, if the MSSC is
1000MW and no wording is changed, the reportable range would be 800MW -1000MW. If “equal to”
is removed, then the reportable range is 801MW – 999MW. (2) R1, 1.2 – this statement may not be
necessary given the language in 4 about the applicability of the standard. It seems redundant. (3)
R1, 1.3 – the word ‘is’ appears to be missing from before the word ‘experiencing’. Also, to be
consistent, the second sentence should say ‘R1 (in its entirety) also shall…’. (4) R1, 1.3 – “an
Balancing Contingency …” should be “a Balancing Contingency” (5) R2 – as in R1, 1.2, the carve out
for an Energy Emergency Alert does not seem necessary given section 4. (6) M2 – Clock Hour is not
consistently capitalized. There is no explanation of what EEA 2 or EEA 3 is. (7) Compliance, 1.4 –
again, the carve out for Energy Emergency Alert does not seem necessary given section 4.
Individual
Robert Blohm
Keen Resources Ltd.
Yes
SUGGESTED IMPROVEMENTS TO THE STANDARD Re R1: Remove the comma before the
parenthesis, in 2 places Re R1.3 To meet FERC’s objection that as written R3 impairs reliability by
stopping recoveries in process from completing, append to the very end of subsection 1.3 of

Requirement R.1: “This exemption does not retroactively apply to any recovery in process. The ACE
compliance threshold of any recovery in process should still be adjusted per Requirement R.1 by all
events subsequent to the last event in recovery that fall within the Contingency Event Recovery
Period of the recovery in process.” Re R2 R2's contingency-reserve requirement should be replaced
by this frequency-adjusted simple time-relative contingency-reserve requirement metric: Monthly
average of (Hourly average Reserve / Hourly average of (GenerationDeployed + Load +
BiasShareOfHourlyAverageDeltaFinMW)) >= >= MSSC / Monthly average of Hourly average of
(GenerationDeployed + Load + BiasShareOfHourlyAverageDeltaFinMW). The frequency adjustment
gives equal weight to the RE’s system reliability obligation as to its load obligation and its generation
deployment. Since bias is a negative number, the frequency adjustment relieves the reserve
requirement when the RE is contributing to over-frequency and increases the reserve requirement
when the RE is deemed to be contributing to under-frequency. Re R3: "experiencing an" should be
"experiences a" SUGGESTED IMPROVEMENTS TO THE BACKGROUND DOCUMENT Re "Requirement
1" section: The second line should not be indented. The outer bullets should be dots, not circles, in
conformity with the Standard's style. There should be no comma before "Or". Re "Compliance
Calculation" section: Insert as the preamble of the section the paragraph "It is very important to
note that compliance is calculated in a way equivalent to the wording of Requirement R1, but in a
way opposite to the wording of R1. In particular, R1 lowers the Target ACE to exempt subsequent
events from the recovery requirement because the Reportable ACE observed by operators cannot be
adjusted for subsequent events. On the other hand, the compliance calculation per CR Form 1 does
not adjust the Target ACE for subsequent events and instead adjusts the Reportable ACE by
removing the subsequent events from the Reportable ACE. The compliance result is the same either
way, but this difference needs to be noted to properly understand the following description and
relate it to the wording of R1." The first bullet's text should be left-hand justified with the first line of
the bullet's text. The bullet's first line should be hanging, not indented. Delete the comma after
"and" in the first bullet. Insert in the following bullets the phrases that are in ALL CAPS o If the PreReportable Contingency Event ACE Value is greater than or equal to zero, then the measured
contingency reserve response equals (a) the megawatt value of the Reportable Balancing
Contingency Event plus (b) the most positive ACE value within its Contingency Event Recovery
Period (and following the occurrence of the last subsequent event, if any, OCCURRING BEFORE OR
WHEN ATTAINING THE MOST POSITIVE REPORTING ACE) plus (c) the sum of the megawatt losses
of subsequent Balancing Contingency Events occurring BEFORE OR WHEN ATTAINING THE MOST
POSITIVE REPORTING ACE within the Contingency Event Recovery Period of the Reportable
Balancing Contingency Event. o If the Pre-Reportable Contingency Event ACE Value is less than zero,
then the measured contingency reserve response equals (a) the megawatt value of the Reportable
Balancing Contingency Event plus (b) the most positive ACE value within its Contingency Event
Recovery Period (and following the occurrence of the last subsequent event, if any, OCCURRING
BEFORE OR WHEN ATTAINING THE MOST POSITIVE REPORTING ACE) plus (c) the sum of the
megawatt losses of subsequent Balancing Contingency Events occurring BEFORE OR WHEN
ATTAINING THE MOST POSITIVE REPORTING ACE within the Contingency Event Recovery Period of
the Reportable Balancing Contingency Event, minus (d) the Pre-Reportable Contingency Event ACE
Value. Re page 8: In the second paragraph “entity(s)” should be “entity’s”. Re page 10, insert the
phrase in ALL CAPS into: SUM_SUBSQ - sum of the megawatt losses of subsequent Balancing
Contingency Events occurring within the Contingency Event Recovery Period of the Reportable
Balancing Contingency Event (MW) AND BEFORE OR WHEN ATTAINING THE MOST POSITIVE
REPORTING ACE. The formulas should be replaced by the standard mathematical notation listed at
http://www.robertblohm.com/BackgroundDocumentMath.doc and cross-referenced to the
spreadsheet which does not allow standard mathematical notation.
Group
PPL NERC Registered Affiliates
Brent Ingebrigtson
These comments are submitted on behalf of the following PPL NERC Registered Affiliates (PPL):
Louisville Gas and Electric Company and Kentucky Utilities Company; PPL Electric Utilities
Corporation, PPL EnergyPlus, LLC; and PPL Generation, LLC, PPL; Susquehanna, LLC; and PPL
Montana, LLC. The PPL NERC Registered Affiliates are registered in six regions (MRO, NPCC, RFC,
SERC, SPP, and WECC) for one or more of the following NERC functions: BA, DP, GO, GOP, IA, LSE,

PA, PSE, RP, TO, TOP, TP, and TSP. Applicability Section: 4.1.1 needs clarification. It is unclear what
“not in active status” means. Specifically, it is unclear whether a BA may be in “active status” by
simply being under an RSG agreement and governing rules. It is unclear whether a BA not choosing
to call on RSG assistance for any single Balancing Contingency Event (whether Reportable or not)
would be considered “not in active status.” This makes R2 unclear as to whether and when the BA is
the Responsible Entity as well as what MSSC and reporting threshold would apply. PPL suggests the
following language: A Balancing Authority that is a member of a Reserve Sharing Group is the
Responsible Entity only for the Reportable Balancing Contingency event(s) during which the
Balancing Authority does not request assistance from the Reserve Sharing Group under the
applicable agreement or governing rules for the Reserve Sharing Group. Rather than prescribe the
commercial arrangements between members of a RSG, the above language respects whatever
arrangements RSG members have put in place recognizing that these arrangements must enable the
group and its members to remain in compliance with all applicable requirements. In R1, the revised
language is still confusing. It is unclear how a Balancing Contingency Event can be both
“subsequent” and “already occurred” to a Reportable Balancing Contingency Event. PPL cannot
suggest a solution as we don’t understand the intent of the added language. In R2, the
calculation/evaluation of the 5 hour/quarter “exception clock” did not need elimination – it needed
explanation. It is unclear whether the exception clock was to be evaluated as the average, mean or
median of the Contingency Reserves held for a Clock Hour. M2 specifies a Clock Hour as the time
increment to be used – Clock Hour should also be stated in R2. PPL suggests that the 5-hour
exception clock be based on the Clock Hour average amount of Contingency Reserves held by the
Responsible Entity (BA or RSG) for the calendar quarter. The elimination of the 5-hour exception
clock and added requirement to maintain an hourly average amount of Contingency Reserve is not
an improvement of R2. As the proposed standard is significantly different from the historical/existing
DCS, a draft RSAW should be provided so Responsible Entities can have an indication of how
compliance will be evaluated.
Group
SERC OC Review Group
Sammy Roberts
Yes
We would like to thank the SDT for their hard work and perseverance in developing this standard as
well as the opportunity to provide comment. A) Requirement 1: Likewise, the changes made to
Requirement 1, while adding to complexity, are positive changes. Additional clarity may be achieved
by restructuring the requirement in tabular form with the simplest scenario listed first.
B)Requirement 2: While we agree with the intent of Requirement 2, we continue to believe that the
proposed language will have unintended consequences from the intended objective and could inject
an unnecessary element into the Balancing Operator’s decision making process. We believe R2
discourages a Balancing Operator from deploying contingency reserves for events that may have an
adverse impact on reliability but do not fall under the proposed definition of a Reportable Balancing
Contingency Event nor occur during an EEA Level 2 or 3. Events of this type could include, but are
not limited to, low ACE due to unexpected load changes, schedule changes, and/or slow unit
response that are adversely affecting Interconnection frequency or transmission flows approaching
IROL’s due to contingencies that have occurred in an adjacent balancing area. Current R2 language:
Except during the Responsible Entity’s Contingency Event Recovery Period and the Responsible
Entity’s Contingency Reserve Restoration Period, or during an Energy Emergency Alert Level 2 or 3
for the Responsible Entity, the Responsible Entity shall maintain an amount of Contingency Reserve,
averaged over each Clock Hour, at least equal to its Most Severe Single Contingency. Recommended
R2 language: Except during the Responsible Entity’s Contingency Event Recovery Period and the
Responsible Entity’s Contingency Reserve Restoration Period, or during an Energy Emergency Alert
Level 2 or 3 for the Responsible Entity, the Responsible Entity shall maintain an amount of
Contingency Reserve, averaged over each Clock Hour, at least equal to its Most Severe Single
Contingency ADD: ,averaged over each Clock Hour. C)We request the SDT to consider adding a subrequirement to address the concern that R2 potentially could discourage a Balancing Operator from
deploying contingency reserves for events that may have an adverse impact on reliability but do not
fall under the proposed definition of a Reportable Balancing Contingency Event nor occur during an
EEA Level 2 or 3. Suggested R2.1 language follows: ADD: R2.1 Contingency reserves will be

restored within the 105 minute recovery + restoration periods following deployment of contingency
reserves for a reliability need. D)The SDT is requested to consider developing a draft RSAW to
accompany this draft standard. The OC Review Group feels it is critical to have the draft RSAW to go
along with the draft standard. E)We respectfully request the SDT review the “averaged over each
Clock Hour,” when an event occurs within the last portion of the hour. The standard should include
language that states that average hourly contingency reserves will not fall below average hourly
MSSC for more than three consecutive clock hour. Summary: We believe that the suggested
modifications above would allow Balancing Operators to utilize the appropriate resources at their
disposal to mitigate events that may have an adverse impact on Interconnection reliability while
establishing a continent-wide contingency reserve policy in accordance with Order 693 and avoiding
increased costs to our customers. The comments expressed herein represent a consensus of the
views of the above named members of the SERC OC Review Group only and should not be construed
as the position of the SERC Reliability Corporation, or its board or its officers.
Individual
Catherine Wesley
PJM Interconnection
Yes
PJM would like to thank the SDT for their hard work and perseverance in developing this standard as
well as the opportunity to provide comment. The changes made to the definition of Reportable
Balancing Contingency Event, while adding to complexity, are positive changes. However, due to the
language in R1.3, the definitions need to clearly define and differentiate the start of the Balancing
Contingency Event and the start of the Reportable Balancing Contingency Event compliance period.
This differentiation is especially important for BCA’s that may begin with a controlled unit runback
but turn into an RBCA when the unit trips offline. Likewise, the changes made to Requirement 1,
while adding to complexity, are positive changes. Additional clarity may be achieved by restructuring
the requirement in tabular form with the simplest scenario listed first. While we agree with the intent
of Requirement 2, we continue to believe that the proposed language will have unintended
consequences from the intended objective and could inject an unnecessary element into the
Balancing Operator’s decision making process. We believe R2 discourages a Balancing Operator from
deploying contingency reserves for events that may have an adverse impact on reliability but do not
fall under the proposed definition of a Reportable Balancing Contingency Event nor occur during an
EEA Level 2 or 3. Events of this type could include, but are not limited to, low ACE due to
unexpected load changes, schedule changes, and/or slow unit response that are adversely affecting
Interconnection frequency or transmission flows approaching IROL’s due to contingencies that have
occurred in an adjacent balancing area. If there was to be a commodity measure in the standard,
there are changes to the current proposal that could relieve the aforementioned concerns. Proposal
#1: The standard could include language that states that contingency reserves shall be restored
within the 105 minute recovery + restoration periods following deployment of contingency reserves
for a reliability need. Proposal #2: Alternatively, the standard could include language that states
that average hourly contingency reserves shall not fall below average hourly MSSC for more than
three consecutive clock hours. Regardless of which of these proposals are adopted, the hourly
contingency reserves should be in reference to average hourly MSSC. This will add clarity for BA’s
that have a dynamic MSSC that changes in real-time. We believe that the suggested modifications
above would allow Balancing Operators to utilize the appropriate resources at their disposal to
mitigate events that may have an adverse impact on Interconnection reliability while establishing a
continent-wide contingency reserve policy in accordance with Order 693 and avoiding increased
costs to our customers.
Group
Associated Electric Cooperative, Inc. - JRO00088
David Dockery
Yes
1) The current draft’s definition and then practical inclusion of Most Severe Single Contingency, has
retained the “MW output” term, yet now includes the concept of lost power import schedules. This
“MW output” term worked fine when the original NERC Policy and then Standard addressed only loss

of Generation within a BA’s footprint. Because sudden cut of an import schedule is unlikely to result
in a sudden decline in net energy export, AECI now seeks clarity for the “MW output” term’s
meaning: 1a. Loss of net generation MW output (likely to be the common BA perception)?, OR 1b.
Loss of MW output from the BA’s footprint, and disregarding scheduled interchange?, OR 1c.
Algebraic decline of inadvertent interchange (Net-Actual-Interchange minus Net-ScheduledInterchange), and disregarding Interchange frequency change?, OR 1d. Algebraic decline of ACE
which typically includes the BA frequency-bias factor applied to any sudden frequency change? 2)
This current draft of NERC Reliability Standard BAL-002-2’s requirements R1 and R2, in conjunction
with EOP-003-2 R1, can cause BAs to unnecessarily shed load, or to be instructed by an RC to do so,
when there is no real risk to BES reliability, and even when Interconnection frequency is quite high,
in direct opposition to the more refined reliability-based BAL-001-2 Standard now awaiting FERC
approval. See AECI’s suggestions #3 and #4. 3) Due to unintentional consequences, this current
draft as well as its predecessors, has a serious scalability issue. Both large BAs and now large RSGs,
necessarily provisioned to allow small BAs some equitable relief under BAL-002, allow and even
encourage creation of artificially over-sized entities, to lower the business-related impact of the BAL002 Standard yet: 1) at a potentially reduced value to overall BES reliability, should they get even
larger, or 2) no real added-value to BES reliability for smaller BAs having been forced into RSGs or
large Market –based BAs. So, unless BAL-002-2 is removed as a Reliability Standard altogether,
AECI proposes two options for a simplified version of this standard, based upon our own experience
of obligations within a reasonably sized RSG: 3a. 5% of each BA or RSG’s largest online unit’s
capability, yet with consideration for multiple constricted areas within their footprint being held to
the same metric. 3b. 0.8% of each BA’s or RSG’s net online generating capability, or net load,
whichever is greater. (AECI favors this as being simple, close to what the large BAs and RSGs are
carrying, and with added benefit of being dispersed within footprints containing smaller BAs.) 4)
Draft BAL-002-2 is now fundamentally a fair business practices standard. All reliability-related issues
historically addressed within BAL-002 predecessor’s requirements or guidelines, now appear to be
better met by the overlapping effects of NERC Requirements found within EOP-001 (Adequate
planning and provision for resources to weather the Most Severe Single Contingency event), BAL001-2 (Ongoing degree of reliability-related Energy and Frequency Imbalance), and BAL-003
(Frequency-response reflecting amount of Spinning-reserve being carried). This explains why SDT
Requirement R2 consideration to allow for up to 5 “failing” hours within a calendar month, was
refuted by argument that such allowance could be abused by Entities deliberately coinciding their
deficiencies with peak-hours, a fair business-practice argument, but then countered by BAL-001-2's
essentially precluding such behavior. So BAL-002-2 is now a candidate for NASB adoption, as they
deem necessary, with removal from the BAL standards. 5) Provided this SDT elects to not entirely
remove BAL-002-2 from the NERC Reliability Standard set or simplify per Options 3a or 3b above,
AECI does favor the SERC OC WG's suggested addition of ", averaged over each Clock Hour" to then
end of R2, as well as R2.1, as well as their part "E)" suggestion for allowing reserves to drop below
MSSC for no more than three consecutive clock hours. Due to current draft complexities, AECI also
favors an RSAW being developed by the SDT ASAP.
Group
DTE Electric
Kathleen Black
Agree
MISO
Group
ACES Standards Collaborators
Jason Marshall
Yes
(1) The addition of Part 1.3 clarifies that the requirement does not apply when the contingency
exceeds its Most Severe Single Contingency (MSSC). Its inclusion obviates the need for the second
sub-bullets of R1 under the first and second main sub-bullets and that begins with “Further reduced
by the magnitude…” These sub-bullets are not needed because they only apply when the Balancing
Contingency Event exceeds the MSSC and Part 1.3 is clear that the main requirement does not apply
in this situation. (2) We continue to believe that the thresholds established in the Reportable

Balancing Contingency Events are arbitrary. There is no supporting evidence for the values that were
selected. The companion background document does include a brief discussion of the thresholds but
it only discusses why 100 MW was not selected and it does not discuss why the thresholds were
selected. What is the justification that the threshold for the Eastern Interconnection cannot be above
900 MW for example? (3) The Reportable Balancing Contingency Event definition is fundamentally
flawed. The last sentence contradicts the statement that the lower threshold is 80%. The lower
threshold is in fact no greater than 80% and is set by the responsible entity upon written notification
to the Regional Entity. If the value will be variable, this should be stated directly in the first sentence
of the requirement to avoid the definition contradicting itself. (4) The Reportable Balancing
Contingency Event definition should be further modified to avoid unnecessary compliance burdens
and paperwork. There is no need to notify the Regional Entity in writing before changing the lower
reporting threshold. The Regional Entity has no documented process in the standard to prevent the
change from occurring so communicating it to the Regional Entity is an unnecessary compliance
burden. The responsible entity should only be obligated to document it. The Rules of Procedure allow
the Regional Entity to request this type of data in several other ways. They could even request it as
part of an annual self-certification as an example. FERC has stated that definitions are considered
standards, and this part of the definition could be viewed as meeting Paragraph 81 criteria because
it is administrative in nature. In particular, it meets criterion B4 because it requires reporting to the
Regional Entity which has “no discernible impact on promoting the reliable operation of the BES.” (5)
The definition of Pre-Reporting Contingency Event ACE Value requires additional justification to
change the pre-disturbance calculation from an average of 10 to 60 seconds of ACE data prior to the
disturbance to a 16-second interval. There is no explanation of this in the background document and
we cannot support such a change without a justification for how it supports reliability. Furthermore,
the definition is not consistent with other reliability standards, such as BAL-005-0.2b which requires
ACE calculation on at least a six-second basis. A BA using a six-second sample rate could be viewed
as being out of compliance if an entity used either two (12 seconds) or three (18 seconds) samples
since they cannot use exactly 16 seconds of data. Furthermore, using only two or three samples
could lead to unrealistic averages particularly if there are any spurious data points. What does an
entity do if a scan was skipped or there was a data spike? More samples would make it less likely for
this to be an issue. (6) While the standard has been modified to provide more flexibility in the use of
Contingency Reserve, there still is not enough flexibility and the standard could have unintended
consequences for reliability. For example, the definition of Contingency Reserve limits the use of
Contingency Reserve to only contingent events. This would prevent the BA from using Contingency
Reserve for other reliability purposes such as to respond to inadequate schedule ramping when other
units don’t ramp as expected. A BA should be free to call upon Contingency Reserve to reduce a
negative ACE for reliability support regardless of whether it is caused by a contingency or some
other event. (7) The “Additional Compliance Section” potentially conflicts with the definition of
Contingency Reserve. Since “Additional Compliance Section” would allow the use of Contingency
Reserve to meet other standards as required this would be a conflict if the use of Contingency
Reserve was to comply with another standard not involving a contingency. The definition of
Contingency Reserve restricts the use to only contingencies. For example, the IRO-005-3.1a R5
compels the BA to utilize all resources to relieve emergency conditions regardless of whether they
were caused by a contingency or not. (8) The data retention required for the current versions of this
standard is too long. BAs submit quarterly data to their regional entities, so they should not be
required to retain three years worth of data. While the standard will no longer compel this quarterly
reporting, this practice is unlikely to change. At the very least, compliance staff should be consulted
to determine if this will continue to be the practice. We strongly recommend the drafting team
collaborate with NERC compliance to develop an RSAW and other compliance guidance. If the RSAW
was developed with the standard, it would facilitate the discussion with industry of how much data is
needed to be retained. (9) The data retention section of the standard exceeds what is allowed in the
NERC Rules of Procedure, Section 3.1.4.2 of Appendix 4C. This section specifies that “the audit
period begins the day after the End Date of the prior Compliance Audit...the audit period will not
begin prior to the End Date of the previous Compliance Audit.” Since BAs are only audited
approximately every three years, the data retention period of up to four years (current year, plus
three previous calendar years) exceeds the three year audit period. (10) Thank you for the
opportunity to comment.
Individual
Gregory Campoli

New York Independent System Operator
Agree
The NYISO supports the comments and questions raised by both the IRC/SRC and NPCC RSC.
Group
SPP Standards Review Group
Robert Rhodes
Yes
In BAL-002-2: We would like to thank the drafting team for the clarification provided in the definition
of Reportable Balancing Contingency Event regarding the intent of ‘sudden’. We also thank the
drafting team for adding the clarification on events larger than an entity’s MSSC as provided in
Requirement R1.3. In the Background Document: On Page 5, in the 3rd line of the 2nd paragraph
under Contingency Reserve, change ‘complimented’ to ‘compliment’. In the 6th line of the same
paragraph, capitalize ‘reserve’ in ‘Operating Reserve’. On Page 11, in the 10th line of the 2nd
paragraph under the Background and Rationale section for Requirement 2, delete the ‘s’ on ‘suites’.
In the last line of the last paragraph on Page 11, replace ‘real-time’ with ‘Real-time.’ In the CR Form
1: Replace ‘Exemp’ with ‘Exempt’ in the title on the Exemption worksheet. Use of terms: DemandSide Management – In the definition of Contingency Reserve in the standard and in the Contingency
Reserve section of the Background Document, use the NERC Glossary of Terms Demand-Side
Management in lieu of Demand Side Management. Clock Hour – In Measure M2, be consistent with
the use of Clock Hour. In some uses the term is capitalized and in others it isn’t.
Individual
Russel Mountjoy
Midwest Reliability Organization
Agree
Midcontinent Independent System Operator (MISO)
Individual
Bret Galbraith
Seminole Electric Cooperative, Inc.
Agree
Duke Energy
Individual
Richard Vine
California ISO
Agree
ISO/RTO Standards Review Committee
Group
Bonneville Power Administration
Jamison Dye
Yes
- Definition R1 refers to ‘Reporting ACE’ and there is no accompanying definition of this term. - BPA
recommends further clarity and explanation for the sudden unplanned outage of a transmission
facility, and sudden restoration of known load used as a resource that causes an unexpected change
to responsible entity’s ACE. - BPA recommends leaving in the Unexpected Failure of Generation to
start language in the definitions section.
Individual
Cheryl Moseley
Electric Reliability Council of Texas, Inc.
No

ERCOT ISO is generally supportive of the IRC SRC comments, the BAL-002-2 standard, and
appreciates the work the SDT has done on the standard and the opportunity to comment. ERCOT
ISO suggests that the 800 MW threshold for ERCOT be removed from the definition of Reportable
Balancing Contingency Event for the ERCOT single-BA area Interconnection and have the calculation
of MSSC apply to single-BA area Interconnections.

Standards Announcement Reminder
Project 2010-14.1 Phase 1 of Balancing Authority Reliabilitybased Controls: Reserves (BAL-002-2)
Additional Ballot and Non-Binding Poll Now Open through December 11, 2013
Now Available

An additional ballot and non-binding poll of the associated Violation Risk Factors (VRFs) and Violation
Severity Levels (VSLs) for BAL-002-2 – Disturbance Control Performance - Contingency Reserve for
Recovery from Balancing Contingency Event is open through 8 p.m. Eastern on Wednesday, December
11, 2013.
Background information for this project can be found on the project page.
Instructions for Balloting

Members of the ballot pools associated with this project may log in and submit their vote for the
standard and non-binding poll of the associated VRFs and VSLs by clicking here.
Next Steps

The ballot results for 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
standard. If the comments do not show the need for significant revisions, the standard will proceed to a
final ballot.
Standards Development Process

The Standards Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller (via email),
Standards Development Administrator, or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE

Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement

Project 2010-14.1 Phase 1 of Balancing Authority Reliability-based
Controls: Reserves (BAL-002-2)
Formal Comment Period: October 28, 2013 – December 11, 2013

Upcoming:
Additional Ballot and Non-Binding Poll: December 2-11, 2013
Now Available
A formal comment period for BAL-002-2 – Disturbance Control Performance - Contingency Reserve
for Recovery from Balancing Contingency Event is open through 8 p.m. Eastern on Wednesday,
December 11, 2013.
Background information for this project can be found on the project page.
Instructions for Commenting
A formal comment period for the standard is open through 8 p.m. Eastern on Wednesday,
December 11, 2013. Please use the electronic comment form to submit comments.
An off-line, unofficial copy of the comment forms are posted on the project page.
Next Steps

An additional ballot and non-binding poll of the associated Violation Risk Factors and Violation Severity
Levels will be conducted Monday, December 2, 2013 through 8 p.m. Eastern on Wednesday,
December 11, 2013.
Standards Development Process
The Standards Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller (via email),
Standards Development Administrator, or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE

Suite 600, North Tower

Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement – Project 2010-14.1

2

Standards Announcement

Project 2010-14.1 Balancing Authority Reliability-based
Controls: Reserves
BAL-002-2
Additional Ballot and Non-Binding Poll Results
Now Available

An additional ballot for BAL-002-2- Contingency Reserve for Recovery from a Balancing
Contingency Event and non-binding poll of the associated Violation Risk Factors and Violation
Severity Levels concluded at 8 p.m. Eastern on Wednesday, December 11, 2013.
Voting statistics for the additional ballot are listed below, and the Ballot Results page provides a link to
the detailed results. This standard achieved a quorum but did not receive sufficient affirmative votes
for approval.
Approval

Non-Binding Poll Results

Quorum: 75.29%

Quorum: 76.62%

Approval: 64.24%

Supportive Opinions: 66.67%

Background information for this project can be found on the project page.
Next Steps

The drafting team will consider all comments received during the formal comment period and, if
needed, make revisions to the standard. If the comments do not show the need for significant
revisions, the standard will proceed to a final ballot.
Standards Development Process

The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.

For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, 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

Announcement – Project 2010-14.1 BAL-002-2

2

NERC Standards



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https://standards.nerc.net/BallotResults.aspx?BallotGUID=86a65920-c1a7-493b-9449-ea6122cb0dfc[12/13/2013 9:15:53 AM]

NERC Standards

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&RQVROLGDWHG(GLVRQ&RRI1HZ MSSC. This does not mean shedding load as long as the BA is not
causing an exceedance of an IROL. One particular challenge is the lack of common definitions for
reserves. The team is proposing a commodity requirement without a definition of how to quantify
the hourly number. We believe that reliability would be better served if the team followed the Order
No. 693 directive to create uniform definitions in a policy document. Once these terms are defined
and commented on by the Industry in the document, NERC should add the types of reserves to
“Attachment 1-TOP-005 Electric System Reliability Data”, with the expectation in the policy that
Reliability Coordinators collect this information in real time for use in the EEA process. We believe
there would be significant reliability value in giving RCs continent-wide visibility of the current state
of Contingency Reserves (something callable in 10 minutes, fully deployed in 15 minutes and
sustainable for at least 90 minutes) and Replacement Reserves (e.g. something callable in 90
minutes and sustainable for say 4 hours). This would directly contribute to reliability by providing
objective information to BAs and RCs in managing Energy Emergency Alerts.
Group
Duke Energy
Michael Lowman
Duke Energy
(1) Duke Energy suggests the following revision to R1.2: “1.2. A Responsible Entity is not subject to
compliance with Requirement R1 when it is experiencing an Energy Emergency Alert under which
Contingency Reserves have been utilized to serve load.” We believe the intent of the SDT was for
the Responsible Entity to be exempt from compliance with R1 during those instances where
Contingency Reserves are utilized to serve load. (2) Duke Energy suggests the following revision to
R2 bullet 3: “• an Energy Emergency Alert under which Contingency Reserves have been utilized to
serve load.” We believe the intent of the SDT was for the Responsible Entity to be exempt from
compliance with R2 during those instances where Contingency Reserves are utilized to serve load.
(3) Duke Energy suggests the following revision to item A.a.ii. of the Balancing Contingency Event
definition: “ii. Loss of generator Facility resulting in isolation of the generator from the Bulk Electric

System or from the responsible entity’s electric system, or…” We believe the use the word
“Interconnection” could be viewed as redundant based on it being implied within the NERC definition
of “Facility”. (4) Duke Energy seeks clarification on item B of the Balancing Contingency Event (BCE)
definition. A BCE should be predicated on a deviation in Area Control Error (ACE) . As written, we are
unclear why item B is even part of the definition because we believe Item B is redundant with item
A.a.ii.
Individual
Spencer Tacke
Modesto Irrigation District
I am voting NO because I cannot support a change from 15 minutes to 105 minutes in Section R1
1.3. I could , however, support a change from 15 minutes to 30 minutes. Thank you.
Individual
Si Truc PHAN
Hydro-Quebec TransEnergie
We believe that this draft certainly is an improvement from the last draft and from the actual
standard. We suggest the SDT to take into account additional minor adjustments to improve the
actual draft. We propose that the standard should follow the new NERC standard format by placing
measures with associated requirements. The proposed definition for "Balancing Contingency Event",
the term "Interconnection Facility" should not be capitalized as it is not a defined term in the NERC
Glossary. Only the term "Facility" should be capitalized. "Interconnection" is a defined term but
refers to one of the major electric system (Eastern, ERCOT, etc.) when capitalized. In this case, the
term "interconnection Facility" seems to refer to a facility that is used to interconnect generation to
the system. In the proposed definition for "Most Severe Single Contingency", the term "sink" should
be capitalized as "Sink Balancing Authority" is a defined term in the NERC Glossary. Also, some
single contingencies may lead to a generation loss as well as a load loss due to bus configuration.
This load could either be end-user load or DC converters. We suggest that the “Reportable Balancing
Contingency Event” and “Most Severe Single Contingency” definitions explicitly take the load loss
into account. We suggest adding the words “… resulting in the net loss of MW output reduced by any
concurrent load loss” in both definitions. We noticed that the background document discusses the
issue stated above in the MSSC section but may not be exact in all cases. For example, a BA has
three 600 MW units in a substation and a 200 MW transformer that serves load. Due to unavailable
equipment in the substation, there is a bus fault that can lead to the loss of two units (1200 MW)
and the transformer (200 MW). In this case, we believe that the entity’s MSSC should be 1000 MW.
This following sentence is not true in all cases: “Since the size of an event where both load and
generation are lost due to the loss of the transmission would be less than just the loss of the
generator, it is impossible for this event to be the entity’s MSSC » . We suggest removing it from
standard. R1: We suggest that the part that addresses Balancing Contingency Event (BCE)
occurrences during the Contingency Event Recovery Period be not duplicated. Moreover, we ask
further explanation about the use of the expression "beginning at the time of". Also, we believe that
part unnecessary. The reduction cannot be applied before a BCE actually happens and the reduction
is applied to the required recovery value that must be reached by the end of the recovery period.
Thus, the time of the application of the reduction is not relevant. As long as the event fully occurs
within the recovery period the adjustment can be made. The expression "beginning at the time of" is
also not consistent with the last sentence of the background document: "Note that the adjustments
to the Reportable ACE value required for recovery are made only after the subsequent Balancing
Contingency Event fully occurs." Whereas the requirement states "…beginning at the time of each
individual Balancing Contingency Event". To address those issues to be more clear and concise, we
suggest rewording the two bullets as follows: "Zero, if its Pre-Reporting Contingency Event ACE
Value was positive or equal to zero Or Its Pre-Reporting Contingency Event ACE Value, if that value
was negative. In both cases, the required recovery value for the Reporting ACE shall be reduced by
the magnitude of each subsequent Balancing Contingency Event that fully occurs during the
Contingency Event Recovery Period." Section 1.2 should be included in 1.3 as it is also a condition
under which R1 does not apply (1.3 would become 1.2). Also in 1.3, the first part addressing BCE >
MSSC is redundant since R1 applies to Reportable BCE which is defined as a BCE <= MSSC. We
suggest removing the first part of 1.3 (i) and only keep the second part (ii). We propose: "1.2
Requirement R1 (in its entirety) does not apply: • when the Responsible Entity is experiencing an

Energy Emergency Alert Level under which Contingency Reserves have been activated, or • after
multiple Balancing Contingency Events for which the combined magnitude exceeds the Responsible
Entity’s Most Severe Single Contingency for those events that occur within a 105 minute period."
The graphs in Attachment 1 of the background document should exclude load events in the
statistics. These events are not relevant for the BAL-002 standard. Additionally, it makes it difficult
to understand how the MW threshold for the Interconnections established from these graphs. The
SDT should explain the data shown in the graphs and how it relates to the Interconnection
minimums. Additionally, “hydroquebec” graph should be renamed “Quebec” Interconnection. In
Attachment 2 of the background document there seem to be a mistake in the example. The second
Balancing Contingency Event (200MW at 12:15) that occurs during the recovery period is cumulative
to the first one resulting in a required ACE recovery value of negative 600 MW. However, the next
sentence states that the responsible entity would return its Reporting ACE to negative 200 MW by
12:20 which would be a more severe requirement in response to a subsequent BCE during a
recovery period. It must be corrected in the background document.
Individual
Catherine Wesley
PJM Interconnection
1. We have the following questions and concerns with the language in the Applicability subsections
for 4.1. Section 4.1.1.1 is problematic in that it states that the RSG is the RE when BA’s are in
‘active status’. Active status is subjective and likely not a defined term in governing RSG
agreements. Additionally, the definition cannot be applied consistently to both R1 and R2. Please
consider the following examples where a BA is assumed to be actively maintaining its reserve
allocation for the RSG. • A BA experiences a Reportable Event in which it recovers ACE and reserves
in accordance with R1 without requesting assistance from the RSG members. The BA is the RE even
though it is in ‘active status’ in the RSG. • For R2 compliance purposes, as long as the BA is actively
maintaining its allocation of reserves in accordance with the governing RSG agreement, the RSG is
the RE. • Applicability for R2 is further complicated when the BA may participate in an RSG for only
part of its footprint and maintains its allocation for the RSG while also maintaining additional
reserves for the MSSC in the overall balancing area. In this example, both the BA and the RSG are
may be RE’s. We believe that to resolve these issues, the BA versus RSG applicability should be
moved to the requirements themselves. The SDT could also consider explicitly stating that a BA is
compliant under R2 when it maintains the average hourly reserves at least equal to its reserve
allocation under the terms of the governing RSG agreement. 2. We recommend the following change
to the proposed language of R1.1. R1.1 All Reportable Balancing Contingency Events will be
documented using CR Form 1 [or an acceptable alternative.] 3. We recommend the following change
to the proposed language of R1.2. R1.2. A Responsible Entity is not subject to compliance with
Requirement R1 when it is experiencing an Energy Emergency Alert Level under which Contingency
Reserves have been activated [or where the Responsible Entity has declared that it may be unable
to meet reserve requirements due to system conditions.] R1.2 Comment: The proposed language is
counterintuitive and creates a compliance concern for the System Operator. A BA may declare an
EEA3 (under the revised language of yet to be approved EOP-011) indicating that it is unable to
meet reserve requirements, but must deploy some of those reserves even if there is no immediate
need to do so, to receive an R1 compliance exemption, making the BA even less able to meet its
reserve requirements. Further, if a BA declares an EEA, indicating that it is unable to meet reserve
requirements, and subsequently deploys some of its reserves to meet increased load does this
constitute a deployment of contingency reserves under R1.2 and what evidence does the BA provide
to demonstrate compliance? 4. We recommend the following changes to the proposed language of
R2. R2. The Responsible Entity shall maintain Contingency Reserve, averaged over each Clock Hour,
greater than or equal to its average Clock Hour Most Severe Single Contingency, except during
periods when the Responsible Entity is in: [Violation Risk Factor: Medium] [Time Horizon: Real-time
Operations] • a restoration period because it has used its Contingency Reserve for Contingencies
that are not Balancing Contingency Events [or in response to a Reliability Directive.] This required
restoration begins when the Responsible Entity’s Contingency Reserve falls below its MSSC and must
not exceed 90 minutes; and/or • a Contingency Event Recovery Period or its subsequent
Contingency Reserve Restoration Period; and/or • an Energy Emergency Alert Level under which
Contingency Reserves have been activated [or where the Responsible Entity has declared that it may
be unable to meet reserve requirements due to system conditions.] R2 Comment: As stated in the

comments for R1.2, the proposed language is counterintuitive and creates a compliance concernfor
the System Operator. A BA may declare an EEA3 (under the revised language of yet unapproved
EOP-011) indicating that it is unable to meet reserve requirements, but must deploy some of those
reserves even if there is no immediate need to do so, to receive an R2 compliance exemption,
making the BA even less able to meet its reserve requirements. Additionally, absent the suggested
language in the first bullet, a BA may receive a Reliability Directive from its RC (see IRO-001 R8) to
deploy Contingency Reserves to mitigate a condition or event that is having an adverse reliability
impact on the BES, but be non-compliant under R2 for following that directive. We believe that R2,
as currently proposed, is unnecessary to satisfy the directive in FERC Order 693 to develop “a
continent-wide contingency reserve policy”, as this was accomplished with the development of
Reliability Guideline: Operating Reserve Management that was approved by the NERC Operating
Committee in October 2013. If, however, the SDT decides that it is necessary to keep the
commodity obligations currently proposed in R2, we believe that the suggested R2 changes above
will reduce unintended adverse reliability consequences while further reinforcing satisfaction of the
directive. Additional Comments: The SDT has failed to demonstrate a performance need, in the form
of negative historical trends for DCS recovery or compliance, for the proposed changes. Significant
negative consequences of the proposed standard include but are not limited to: 1) The proposed
language moves this project from being a performance based standard to a commodity obligation.
2) Creates a daunting and unnecessary administrative burden in tracking the commodity obligations
set forth in Requirement 2. For example, the following are just a few of the evidence requirements in
the RSAW: a. R2 requires dated documentation that demonstrates that hourly Contingency Reserves
were at least equal to hourly MSSC. In a three year audit period that is 26,280 one hour intervals! b.
Both R1 & R2 require dated documentation for all Reportable Balancing Contingency Events that
occur when an EEA and Contingency Reserves have been activated. When an RE declares an EEA2 or
EEA3, under the current TOP standard, they are declaring that they may be unable to meet required
reserve requirements. When the load increases after the EEA has been declared and units that were
previously providing CR are then dispatched higher to balance the increased load, does that
constitute deploying CR? What evidence does the RE provide? 3) Increased customer costs absent a
demonstrated reliability need as BA’s are incented to purchase additional contingency reserves
beyond that needed to recover from the loss of MSSC. 4) Increased frequency variation as BA’s are
incented to change generation dispatch at the top of each hour to meet the R2 commodity
obligation. 5) Increased SOL & IROL exceedance durations as BA’s are reluctant to deploy reserves
to mitigate. 6) As stated above, this standard creates a compliance concernfor System Operators
who may have to choose between activating reserves and shedding load for non-Reportable events
OR following Reliability Directives under IRO-001 and maintaining reserves under BAL-002 R2. 7) An
increase in BAAL excursion minutes & frequency variation as BA’s are discouraged from activating
reserves for non-reportable events that are having an adverse impact on system frequency. 8)
Provides a disincentive for a BA to assist its neighbor when a formal RSG Agreement is not in effect.
9) The Severe VSL omits the “from a Reportable Balancing Contingency Event” language that is
included in the Lower, Moderate, & High VSLs. We believe this omission was an oversight. 10) The
Background Document states on page 4 that “BAAL also ensures the Responsible Entity balances
resources and demand for events of less magnitude than a Reportable Balancing Contingency” while
R2 discourages the System Operator from using one of the important tools for accomplishing that
task; Contingency Reserves. 11) The Background Document states on page 5 that “FERC Order 693
(at 355) directed entities to include a Requirement that measures response for any event or
contingency that causes a frequency deviation”. Order 693 (at P355) directs the ERO to “define a
significant deviation and a reportable event”. This misstatement in the Background Document is
significant and should be corrected. 12) The Background Document states on page 6 that “the
drafting team elected to allow the Responsible Entity to use its Contingency Reserve while in a
declared Energy Emergency Alert 2 or Energy Emergency Alert 3”. This statement is inconsistent
with the current posting. 13) The Background Document (Attachment 1) contains a series of box
plots for each Interconnection labeled “Frequency Events Loss MW Statistics”. a. The SDT should
include a summary of what this data represents, including event threshold criteria used to determine
the sample. b. The data appears to show loss of generation and loss of load events in the same
samples. If the intent is to show statistical correlation between the MW size of an event and
magnitude of frequency deviation then loss of generation and loss of load events should be
separated.
Individual

Cheryl Moseley
Electric Reliability Counccil of Texas, Inc.
ERCOT generally supports the comments submitted by the ISO/RTO Council’s Standards Review
Committee (IRC SRC) and provides the following additional comments: 1. ERCOT respectfully
submits the following comments to remove ambiguity and streamline the definitions proposed to
support this draft of the BAL-002-2 standard: a. The use of the term sudden is ambiguous and could
create confusion. The following revisions are proposed: Balancing Contingency Event: Any single
event described in Subsections (A), (B), or (C) below, or any series of such otherwise single events,
with each separated from the next by less than one minute. A. Unexpected loss of generation: a.
Due to i. Unit tripping ii. Loss of generator Interconnection Facility resulting in isolation of the
generator from the Bulk Electric System iii. Unexpected, unplanned outage of transmission Facility;
b. And, that causes an unexpected change to the responsible entity’s ACE; B. Unexpected loss of an
import, due to unplanned outage of transmission equipment that causes an unexpected imbalance
between generation and load within the Balancing Authority Area. C. Unexpected restoration of a
load utilized as a supply resource to balance load and supply in the Balancing Authority Area that
causes an unexpected change to the responsible entity’s ACE. b. The definition of Most Severe Single
Contingency should be streamlined to ensure that it is clear and unambiguous. The use of phrases
such as “at the time of the event” could create confusion and should be eliminated from the
definition. The following revisions are proposed: Most Severe Single Contingency (MSSC): The
Balancing Contingency Event, due to a single contingency, that would result in the greatest loss
(measured in MW) of resource output used by the responsible entity to meet firm system load and
export obligation (excluding export obligation for which Contingency Reserve obligations are being
met by the sink Balancing Authority). c. The definition of Reportable Balancing Contingency Event
should be streamlined to ensure that it is clear and unambiguous. The use of phrases such as “at the
time of the event” could create confusion and should be eliminated from the definition. The following
revisions are proposed: Reportable Balancing Contingency Event: Any Balancing Contingency Event
causing a loss of MW output less than or equal to 80% of the Most Severe Single Contingency or the
amount listed below for the applicable Interconnection and occurring within a one-minute interval of
the initial decline in ACE based on EMS scan rate data. Prior to any given calendar quarter, the 80%
threshold may be reduced by the Responsible Entity upon written notification to the Regional Entity.
• Eastern Interconnection - 900 MW • The Western Interconnection – 500 MW • ERCOT – 1000 MW
• Quebec – 500 MW d. The definition of Contingency Event Recovery Period should be streamlined to
ensure that it is consistent with other definitions and concepts within the proposed standards and is
clear and unambiguous. The following revisions are proposed: Contingency Event Recovery Period: A
period beginning at the conclusion of a Reportable Balancing Contingency Event and extends for
fifteen minutes thereafter. e. The definition of Contingency Reserve Restoration Period should be
streamlined to ensure that it is clear and unambiguous. The following revisions are proposed:
Contingency Reserve Restoration Period: A period of 90 minutes following the end of the
Contingency Event Recovery Period. f. The definition of Contingency Reserve should be streamlined
to ensure that it is clear and unambiguous. The following revisions are proposed: Contingency
Reserve: Capacity that may be deployed by the Responsible Entity to balance load and supply within
its Balancing Authority Area. The capacity may be provided by resources such as Demand Side
Management (DSM), Interruptible Load and unloaded generation. 2. ERCOT has the following
questions and concerns with the language in the Applicability subsections for 4.1. a. ERCOT
respectfully submits that the Applicability Section is not the appropriate section within a standard to
establish clarifications or compliance exceptions. This could create confusion as to when the
standard is applicable to particular entities. ERCOT would prefer that all references to possible
compliance exceptions are additional criteria that are addressed in Requirements and should be
removed from the Applicability Section. To ensure that these additional criteria are retained within
the standard, the requirements themselves should be reviewed and BA versus RSG applicability
should be addressed within the requirements themselves. The SDT could also consider explicitly
stating that a BA is compliant under R2 when it maintains the average hourly reserves at least equal
to its reserve allocation under the terms of the governing RSG agreement. In the alternative, to
ensure clarity, the following revisions are proposed: 4. Applicability: Applicability is determined on
an individual Reportable Balancing Contingency Event basis. 4.1. Responsible Entity 4.1.1 Balancing
Authority that is not an Energy Emergency Alert Level under which Contingency Reserves have been
activated. 4.1.2 Reserve Sharing Group that is (1) active within a particular Balancing Authority Area
under the applicable agreement or governing rules for the Reserve Sharing Group and (2) not an

Energy Emergency Alert Level under which Contingency Reserves have been activated. 3. ERCOT
respectfully submits that the Requirement R1 is unnecessarily complex and could be streamlined to
present more definitive requirements and criteria. To ensure clarity, the following revisions are
proposed: R1. The responsible entity experiencing a Reportable Balancing Contingency Event shall
return to its pre-Reporting Contingency Event Reporting ACE within the Contingency Event Recovery
Period. [Violation Risk Factor: Medium][Time Horizon: Real-time Operations] • If the responsible
entity’s Pre-Reporting Contingency Event Reporting ACE Value was positive or equal to zero,
recovery shall be demonstrated by returning its Reporting ACE to zero. • If the responsible entity’s
Pre-Reporting Contingency Event Reporting ACE Value was negative, recovery shall be demonstrated
by returning its Reporting ACE to the value utilized for Reporting ACE immediately preceding the
start of the Reportable Contingency Event. o When subsequent Balancing Contingency Events occur
during the Contingency Event Recovery Period, the Reporting ACE value to be recovered shall be
reduced at the start of and by the magnitude of each subsequent Balancing Contingency Event that
occurs during the Contingency Event Recovery Period. Corresponding revisions are suggested to the
VSLs and Measures as necessary to ensure consistency. 4. Requirement R1.1 is administrative in
nature and should be removed from the Standard and included in the ROP or a guidance document.
As an alternative to removing the requirement, ERCOT recommends the following change to the
proposed language of R1.1 to provide an alternative to using CR Form 1. R1.1 All Reportable
Balancing Contingency Events will be documented using CR Form 1 [or an acceptable alternative.]
Corresponding revisions are suggested to the VSLs and Measures as necessary to ensure
consistency. 5. ERCOT suggested above that compliance exceptions be more appropriately
documented in the requirements. Further, the proposed language creates a potential adverse
reliability consequence and operational concern for the System Operator because a Balancing
Authority may declare an EEA3 (under the revised language of yet to be approved EOP-011) to
indicate that it is unable to meet reserve requirements, but deployment of reserves may not yet be
necessary. However, to receive an R1 compliance exemption, the BA would need to deploy some of
those reserves - even if there is no immediate need to do so. This requirement would result in the
impacted BA being even less able to meet its reserve requirements. Further, where subsequent
reserve deployments occur to meet increased load, it is unclear as to whether this would constitute a
deployment of contingency reserves under R1.2. If so, what evidence does the BA provide to
demonstrate compliance? To resolve these issues as well as those discussed under Requirement
R1.3, ERCOT recommends the following change to the proposed language of R1.2. R1.2. A
Responsible Entity is not subject to compliance with Requirement R1 when: (i) It is experiencing an
Energy Emergency Alert Level under which Contingency Reserves have been activated. (ii) It has
declared that it may be unable to meet reserve requirements due to system conditions (iii) It
experiences a Balancing Contingency Event that exceeds its Most Severe Single Contingency. (iv)
The combined magnitude of multiple Balancing Contingency Events occurring within a 15 minute
period exceeds the Responsible Entity’s Most Severe Single Contingency. Corresponding revisions
are suggested to the VSLs, Measures, and Associated Compliance Information as necessary to
ensure consistency. 6. ERCOT suggests the deletion of Requirement R1.3 and the consolidation of all
exceptions from compliance into one Requirement for ease of review and comprehension.
Corresponding revisions are suggested to the VSLs and Measures as necessary to ensure
consistency. 7. ERCOT respectfully submits that R2, as currently proposed, is unnecessary to satisfy
the directive in FERC Order 693 to develop “a continent-wide contingency reserve policy”, as this
was accomplished with the development of Reliability Guideline: Operating Reserve Management
that was approved by the NERC Operating Committee in October 2013. Accordingly, the SDT
recommends the deletion of Requirement R2. Additionally, ERCOT reiterates its operational and
reliability concerns set forth in Comment 6 above and notes that Requirement R2 should
acknowledge the potential impacts of responding to a Reliability Directive. Specifically, a BA may
receive a Reliability Directive from its RC (see IRO-001 R8) to deploy Contingency Reserves to
mitigate a condition or event that is having an adverse reliability impact on the BES, but be noncompliant under R2 for following that directive. Accordingly, as an alternative to deletion of
Requirement R2, ERCOT suggests the following changes to the proposed language of Requirement
R2 to reduce ambiguity and the potential for unintended adverse reliability consequences and satisfy
the aforementioned directive: R2. The Responsible Entity shall maintain Contingency Reserves
greater than or equal to its Most Severe Single Contingency. Such reserves shall be measured using
the average Contingency Reserve amount over each clock hour except when the Responsible Entity
is in: [Violation Risk Factor: Medium] [Time Horizon: Real-time Operations] • For the restoration

period following Contingency Reserve deployment in response to a Contingencies that are not
Balancing Contingency Events or a Reliability Directive, which restoration period shall not exceed 90
minutes and begins when the Responsible Entity’s Contingency Reserve falls below its MSSC; and/or
• a Contingency Event Recovery Period or its subsequent Contingency Reserve Restoration Period;
and/or • an Energy Emergency Alert Level under which Contingency Reserves have been activated
[or where the Responsible Entity has declared that it may be unable to meet reserve requirements
due to system conditions.] Corresponding revisions are suggested to the VSLs and Measures as
necessary to ensure consistency. Additional Comments: 1. ERCOT respectfully notes that a reliability
or performance-related need, such as negative historical trends for DCS recovery or compliance, has
not been noted and, therefore, the proposed changes may not be necessary to ensure the reliability
of the Bulk Electric System. ERCOT supports the clarification and improvement of Reliability
Standards generally. In this circumstance, significant negative consequences of the proposed
standard have been identified. These include, but are not limited to: a. The transformation of
Contingency Reserve requirements from a reliability standard to a commodity obligation. b.
Increased customer costs despite the absence of a demonstrated reliability need as BAs will be
incentivized to purchase contingency reserves beyond that needed to recover from the loss of MSSC.
c. Operational modifications and concerns such as: i. Increased frequency variation as BAs will be
incentivized to change generation dispatch at the top of each hour to meet the R2 commodity
obligation. ii. Increased SOL & IROL exceedance durations as BAs will be reluctant to deploy
reserves to mitigate impacts. iii. Increased BAAL excursion minutes as BAs are discouraged from
activating reserves for non-reportable events that are having an adverse impact on system
frequency. d. Provision of a disincentive for a BA to assist its neighbor when a formal RSG
Agreement is not in effect. e. Creation of a daunting and unnecessary administrative burden in
tracking the commodity obligations set forth in Requirement 2. For example, the following are just a
few of the evidence requirements in the RSAW: i. R2 requires dated documentation that
demonstrates that hourly Contingency Reserves that were at least equal to the MSSC. In a three
year audit period that is 26,280 one hour intervals. 1. ERCOT respectfully notes the following
potential inconsistencies and omissions in the BAL-002 Standard and associated documentation: a.
The Severe VSL omits the “from a Reportable Balancing Contingency Event” language that is
included in the Lower, Moderate, & High VSLs. b. The Background Document states on page 4 that
“BAAL also ensures the Responsible Entity balances resources and demand for events of less
magnitude than a Reportable Balancing Contingency” while R2 discourages the System Operator
from using one of the important tools for accomplishing that task; Contingency Reserves. c. The
Background Document states on page 5 that “FERC Order 693 (at 355) directed entities to include a
Requirement that measures response for any event or contingency that causes a frequency
deviation”. However, Order 693 (at P355) directs the ERO to “define a significant deviation and a
reportable event”. This should be corrected. d. The Background Document states on page 6 that “the
drafting team elected to allow the Responsible Entity to use its Contingency Reserve while in a
declared Energy Emergency Alert 2 or Energy Emergency Alert 3”. This statement is inconsistent
with the current posting and should be corrected. e. The Background Document (Attachment 1)
contains a series of box plots for each Interconnection labeled “Frequency Events Loss MW
Statistics”. i. The SDT should include a summary of what this data represents, including event
threshold criteria used to determine the sample. ii. The data appears to show loss of generation and
loss of load events in the same samples. If the intent is to show statistical correlation between the
MW size of an event and magnitude of frequency deviation, then loss of generation and loss of load
events should be separated.
Group
SERC OC Review Group
Steve Corbin
SERC RRO
1. We have the following questions and concerns with the language in the Applicability subsections
for 4.1. Section 4.1.1.1 is problematic in that it states that the RSG is the RE when BA’s are in
‘active status’. Active status is subjective and likely not a defined term in governing RSG
agreements. Additionally, the definition cannot be applied consistently to both R1 and R2. Please
consider the following examples where a BA is assumed to be actively maintaining its reserve
allocation for the RSG. • A BA experiences a Reportable Event in which it recovers ACE and reserves
in accordance with R1 without requesting assistance from the RSG members. The BA is the RE even

though it is in ‘active status’ in the RSG. • For R2 compliance purposes, as long as the BA is actively
maintaining its allocation of reserves in accordance with the governing RSG agreement, the RSG is
the RE. • Applicability for R2 is further complicated when the BA may participate in an RSG for only
part of its footprint and maintains its allocation for the RSG while also maintaining additional
reserves for the MSSC in the overall balancing area. In this example, both the BA and the RSG are
may be RE’s. We believe that to resolve these issues, the BA versus RSG applicability should be
moved to the requirements themselves. The SDT could also consider explicitly stating that a BA is
compliant under R2 when it maintains the average hourly reserves at least equal to its reserve
allocation under the terms of the governing RSG agreement. R1 – clarity needs to be added to phase
“(i) beginning at the time of” to explain how this phrase applies. 2. We recommend the following
change to the proposed language of R1.1. R1.1 All Reportable Balancing Contingency Events will be
documented using CR Form 1 [or an acceptable alternative.]
3. We recommend the following
change to the proposed language of R1.2. R1.2. A Responsible Entity is not subject to compliance
with Requirement R1 when it is experiencing an Energy Emergency Alert Level under which
Contingency Reserves have been activated [or where the Responsible Entity has declared that it may
be unable to meet reserve requirements due to system conditions.] R1.2 Comment: The proposed
language is counterintuitive and creates a compliance trap for the System Operator. A BA may
declare an EEA3 (under the revised language of yet to be approved EOP-011) indicating that it is
unable to meet reserve requirements, but must deploy some of those reserves even if there is no
immediate need to do so, to receive an R1 compliance exemption, making the BA even less able to
meet its reserve requirements. Further, if a BA declares an EEA, indicating that it is unable to meet
reserve requirements, and subsequently deploys some of its reserves to meet increased load does
this constitute a deployment of contingency reserves under R1.2 and what evidence does the BA
provide to demonstrate compliance? 4. We recommend the following changes to the proposed
language of R2. R2. The Responsible Entity shall maintain Contingency Reserve, averaged over each
Clock Hour, greater than or equal to its average Clock Hour Most Severe Single Contingency, except
during periods when the Responsible Entity is in: [Violation Risk Factor: Medium] [Time Horizon:
Real-time Operations] • a restoration period because it has used its Contingency Reserve for
Contingencies that are not Balancing Contingency Events. This required restoration begins when the
Responsible Entity’s Contingency Reserve falls below its MSSC and must not exceed 90 minutes;
and/or • response to a Reliability Directive; and/or • a Contingency Event Recovery Period or its
subsequent Contingency Reserve Restoration Period; and/or • an Energy Emergency Alert Level
under which Contingency Reserves have been activated [or where the Responsible Entity has
declared that it may be unable to meet reserve requirements due to system conditions.] R2
Comment: As stated in the comments for R1.2, the proposed language is counterintuitive and
creates a compliance trap for the System Operator. A BA may declare an EEA3 (under the revised
language of yet unapproved EOP-011) indicating that it is unable to meet reserve requirements, but
must deploy some of those reserves even if there is no immediate need to do so, to receive an R2
compliance exemption, making the BA even less able to meet its reserve requirements. Additionally,
absent the suggested language in the first bullet, a BA may receive a Reliability Directive from its RC
(see IRO-001 R8) to deploy Contingency Reserves to mitigate a condition or event that is having an
adverse reliability impact on the BES, but be non-compliant under R2 for following that directive. We
believe that R2, as currently proposed, is unnecessary to satisfy the directive in FERC Order 693 to
develop “a continent-wide contingency reserve policy”, as this was accomplished with the
development of Reliability Guideline: Operating Reserve Management that was approved by the
NERC Operating Committee in October 2013. If, however, the SDT decides that it is necessary to
keep the commodity obligations currently proposed in R2, we believe that the suggested R2 changes
above will reduce unintended adverse reliability consequences while further reinforcing satisfaction
of the directive. Additional Comments: The SDT has failed to demonstrate a performance need, in
the form of negative historical trends for DCS recovery or compliance, for the proposed changes.
Significant negative consequences of the proposed standard include but are not limited to: 1) The
proposed language moves this project from being a performance based standard to a commodity
obligation. 2) Creates a daunting and unnecessary administrative burden in tracking the commodity
obligations set forth in Requirement 2. For example, the following are just a few of the evidence
requirements in the RSAW: a. R2 requires dated documentation that demonstrates that hourly
Contingency Reserves were at least equal to hourly MSSC. In a three year audit period that is
26,280 one hour intervals! b. Both R1 & R2 require dated documentation for all Reportable Balancing
Contingency Events that occur when an EEA and Contingency Reserves have been activated. When

an RE declares an EEA2 or EEA3, under the current TOP standard, they are declaring that they may
be unable to meet required reserve requirements. When the load increases after the EEA has been
declared and units that were previously providing CR are then dispatched higher to balance the
increased load, does that constitute deploying CR? What evidence does the RE provide? 3) Increased
customer costs absent a demonstrated reliability need as BA’s are incented to purchase additional
contingency reserves beyond that needed to recover from the loss of MSSC. 4) Increased frequency
variation as BA’s are incented to change generation dispatch at the top of each hour to meet the R2
commodity obligation. 5) Increased SOL & IROL exceedance durations as BA’s are reluctant to
deploy reserves to mitigate. 6) As stated above, this standard creates a compliance trap for System
Operators who may have to choose between activating reserves and shedding load for nonReportable events OR following Reliability Directives under IRO-001 and maintaining reserves under
BAL-002 R2. 7) An increase in BAAL excursion minutes & frequency variation as BA’s are
discouraged from activating reserves for non-reportable events that are having an adverse impact
on system frequency. 8) Provides a disincentive for a BA to assist its neighbor when a formal RSG
Agreement is not in effect. 9) The Severe VSL omits the “from a Reportable Balancing Contingency
Event” language that is included in the Lower, Moderate, & High VSLs. We believe this omission was
an oversight. 10) The Background Document states on page 4 that “BAAL also ensures the
Responsible Entity balances resources and demand for events of less magnitude than a Reportable
Balancing Contingency” while R2 discourages the System Operator from using one of the important
tools for accomplishing that task; Contingency Reserves. 11) The Background Document states on
page 5 that “FERC Order 693 (at 355) directed entities to include a Requirement that measures
response for any event or contingency that causes a frequency deviation”. Order 693 (at P355)
directs the ERO to “define a significant deviation and a reportable event”. This misstatement in the
Background Document is significant and should be corrected. 12) The Background Document states
on page 6 that “the drafting team elected to allow the Responsible Entity to use its Contingency
Reserve while in a declared Energy Emergency Alert 2 or Energy Emergency Alert 3”. This statement
is inconsistent with the current posting. 13) The Background Document (Attachment 1) contains a
series of box plots for each Interconnection labeled “Frequency Events Loss MW Statistics”. a. The
SDT should include a summary of what this data represents, including event threshold criteria used
to determine the sample. b. The data appears to show loss of generation and loss of load events in
the same samples. If the intent is to show statistical correlation between the MW size of an event
and magnitude of frequency deviation then loss of generation and loss of load events should be
separated. c. Last step in example on Page 22 of the redline version, the -200 MW appears to be
incorrect. The required ACE Recovery should be -600 MW. The comments expressed herein
represent a consensus of the views of the above-named members of the SERC OC Review Group
only and should not be construed as the position of SERC Reliability Corporation, its board, or its
officers.
Individual
Sonya Green-Sumpter
South Carolina Electric & Gas
NA
Group
Associated Electric Cooperative, Inc. - JRO00088
Phil Hart
Associated Electric Cooperative, Inc. - NCR01177
AECI agrees with SERC comments 2, 3, and 4. The SDT has used the term “sudden loss” and
“sudden decline” in the definitions for Balancing Contingency Event and Reportable Balancing
Contingency Event. Would the SDT provide some additional guidance on what specially would be
considered “sudden”? Should this be determined from a percentage of the unit lost over a time
period? Would the SDT be able to provide an example of what is considered sudden and what is not
(in addition to including language in the standard that aligns with this example)? AECI agrees with
SERC that the use of “active status” within 4.1.1.1 is ambiguous and AECI suggests the SDT include
more direction on what active status entails. However, inclusion of this concept within the
requirements (as opposed to the applicability) may create more confusion than simply including
more direction on what active status actually is. Serious consideration should made for whatever
language to avoid the unintentional consequence of a BA in an RSG being required to cover their full

MSSC reserves when not in “active status” of the RSG. To this end, it may be advantageous to apply
the exception to the RSG, and not the BA. Proposed 4.1.1.1: A Balancing Authority is the
Responsible Entity when contractual membership to a Reserve Sharing Group does not exist.
Proposed 4.1.1.2: A Reserve Sharing Group is the Responsible Entity for all Balancing Authority
members under contract of that Reserve Sharing Group. AECI suggests the Contingency Event
Recovery Period should be 30 minutes to align with other standards (BAAL).
Individual
Jo-Anne Ross
Manitoba Hydro
1) R 1.2 states: A Responsible Entity is not subject to compliance with Requirement R1 when it is
experiencing an Energy Emergency Alert Level under which Contingency Reserves have been
activated. R 1.3 states: Requirement R1 (in its entirety) does not apply: • (i) when the Responsible
Entity experiences a Balancing Contingency Event that exceeds its Most Severe Single Contingency,
or • (ii) after multiple Balancing Contingency Events for which the combined magnitude exceeds the
Responsible Entity’s Most Severe Single Contingency for those events that occur within a 105 minute
period. R 1.2 could be added as a bullet point in R 1.3 unless there is something that distinguishes
1.2 from 1.3. If so, this should be made clear. 2) M2 states: "If any portion of the Clock Hour is
excluded by rule (restoration period following a Contingency which is not a Balancing Contingency
Event, an Energy Emergency Alert Level user which Contingency Reserves have been activated,
Contingency Reserve Recovery Period overlap or Contingency Reserve Restoration Period overlap)
then that Clock Hour is excluded from evaluation." The terminology “excluded by rule” is currently
unclear and could be clarified by referring to time periods that are excluded in R2. 3) D 1.1 states:
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. This does not take Canadian legislation into account as the term “Compliance
Enforcement Authority” can have different meanings in jurisdictions outside of the United States. An
additional sentence could be added stating that “ In jurisdictions outside the United States the term
“Compliance Enforcement Authority” may designate different entities and / or prescribe different
roles.”
Group
Southern Company: Southern Comapny 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 Operations Compliance
R1.2 Southern suggest that both the EOP-11 and BAL-002-2 SDTs should work together since the
proposed language in R1.2 of BAL-002-2 may contradict the revised language of proposed.EOP-011,
Attachment 1, regarding maintaining contingency reserves during an EEA condition.
Group
SPP Standards Review Group
Robert Rhodes
Southwest Power Pool
BAL-002-2 Comments: We would like to thank the drafting for adding the clarification in the
Balancing Contingency Event definition that establishes the sudden loss/restoration as that change
in generation, import or load that satisfies the reporting criterion within a one-minute sliding
window. This is very helpful. However, we would appreciate seeing the explanation contained in the
Consideration of Comment in an Application Guideline, Associated Document, etc. section included at
the end of the standard. Please hyphenate ’16-second interval’ in the definition of Pre-Reporting
Contingency Event ACE Value. Please hyphenate Demand-Side Management in the definition of
Contingency Reserve to make it consistent with the term in the Glossary. Responsible Entity does
not appear in the NERC Glossary nor is it capitalized in the Functional Model. In fact, the Functional
Model encourages the use of the term as ‘responsible entity’. Shouldn’t this standard be changed to
reflect that recommended usage? Thank you also for further clarifying that the responsible entity is
not subject to compliance with this standard during periods when the responsible entity is in an
Energy Emergency Alert Level in which Contingency Reserves have been activated. Hopefully, this

will be understood by the Emergency Operations drafting team. Again, thank you for the clarifying
changes to Requirement R1. It is much easier to read than the previous version. In Requirement R1,
Part 1.3(ii) hyphenate ‘105-minute period’. In Requirement R2, the responsible entity is required to
maintain Contingency Reserve, averaged over each Clock Hour. Can the drafting team provide any
insight into a recommended scan rate for this averaging? Also, a similar average Clock Hour Most
Severe Single Contingency (MSSC) is established as the bar for compliance. How often does the
drafting team expect MSSC to change? Is this averaging done on a similar basis as Contingency
Reserve? In the past, MSSC has been set based on system norms for a given period – for example a
year in the existing standard and then modified daily on an availability basis. Does the drafting team
really mean an average MSSC for the hour or is it the Real-time value of MSSC during the hour? In
the 3rd line of M2, change ‘documenting’ to ‘documented’. Background Document Comments: In the
5th line of the 1st paragraph of the Introduction, change ‘are’ to ‘were’. This paragraph refers to
historical events and even though the requirement is still active, past tense would be the preferred
usage. Please hyphenate Demand-Side Management in the 4th line of the 1st paragraph under
Contingency Reserve to make it consistent with the term in the Glossary. Responsible Entity does
not appear in the NERC Glossary nor is it capitalized in the Functional Model. In fact, the Functional
Model encourages the use of the term as ‘responsible entity’. Shouldn’t this document be changed to
reflect that usage? The Emergency Operations drafting team has proposed to eliminate the term
Energy Deficient Entity in the new EOP-011-1 standard. Shouldn’t that terminology be phased out in
the Background Document in the 4th line of the 2nd paragraph under Contingency Reserve? In the
4th paragraph under Background and Rationale for Requirement R1, capitalize Parts as in ‘R1 Parts
1.2 and 1.3’. Also, delete the ‘R’ in front of 1.3. In the 3rd line of the same paragraph, use lower
case ‘standards’ or use 'Reliability Standards'. In the 1st line of the 5th paragraph under Background
and Rationale for Requirement R1, insert a ‘the’ between ‘by’ and ‘Consortium’. In the 9th line of the
4th paragraph under Background and Rationale for Requirement R2, capitalize ‘Real-time’. The
language of the 2nd and 3rd subsequent events in the Attachment 2 example is very confusing. We
recommend rewording the 1st line at the top of Page 20 (the 2nd subsequent event in the example)
to read ‘…required ACE recovery being reduced by 400 MW to -400 MW.’ Similarly, in the 3rd
subsequent event in the 3rd line of the paragraph below the bullets on Page 20, reword the line to
read ‘…required ACE recovery being reduced by another 200 MW to -600 MW.’ We recommend that
the RSAW be revised to reflect the modified language we have proposed for the standard.
Group
Bonneville Power Administration
Andrea Jessup
Transmission Reliability Standards Group
BPA is in agreement with the proposed standard, however, believes there should be a clarifying
comment in requirement R1. In R1, following the second bullet, BPA would like to state: For all
subsequent events that occur during the initial Contingency Event Recovery Period, the PreReporting Contingency Event ACE Value for that initial event must be used for the subsequent
event(s). BPA has included an example using the Example in Attachment 2 of the NERC BAL-002
Background Document to demonstrate and add clarity to the statement above. The example includes
a diagram that will emailed separately to Darrel Richardson (NERC Standards Developer) and Jerry
Rust, SDT member.
Individual
Robert Blohm
Keen Resources Ltd.
Consideration of the changes I repeatedly proposed here http://www.robertblohm.com/BAL-002-2
was repeatedly put off by the drafting team. Please consider them now. I proposed the changes here
http://www.robertblohm.com/BAL-002-2-Background-Document in the previous comment round
and, together with my comments on them in that round, they were never addressed by the drafting
team. Please consider them this time.

Standards Announcement Reminder

Project 2010-14.1 Phase 1 of Balancing Authority Reliabilitybased Controls: Reserves
BAL-002-2
Additional Ballot Now Open through October 2, 2014
Now Available

An additional ballot for the BAL-002-2 – Disturbance Control Performance -Contingency Reserve for
Recovery from a Balancing Contingency Event and non-binding poll of the associated Violation Risk
Factors (VRFs) and Violation Severity Levels (VSLs) are now open through 8 p.m. Eastern on
Thursday, October 2, 2014.
Background information for this project can be found on the project page.
Instructions for Balloting

Members of the ballot pools associated with this project may log in and submit their vote for the
standards, definitions, implementation plan and associated VRFs and VSLs by clicking here.
Note: If a member cast a vote in the initial ballot, that vote will not carry over to the additional
ballot. It is the responsibility of the registered voter in the ballot pool to cast a vote again in the
additional ballot. To ensure a quorum is reached, if you do not want to vote affirmative or negative,
please cast an abstention.
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.
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 Reminder

Project 2010-14.1 Phase 1 of Balancing Authority Reliabilitybased Controls: Reserves
BAL-002-2
Additional Ballot Now Open through October 2, 2014
Now Available

An additional ballot for the BAL-002-2 – Disturbance Control Performance -Contingency Reserve for
Recovery from a Balancing Contingency Event and non-binding poll of the associated Violation Risk
Factors (VRFs) and Violation Severity Levels (VSLs) are now open through 8 p.m. Eastern on
Thursday, October 2, 2014.
Background information for this project can be found on the project page.
Instructions for Balloting

Members of the ballot pools associated with this project may log in and submit their vote for the
standards, definitions, implementation plan and associated VRFs and VSLs by clicking here.
Note: If a member cast a vote in the initial ballot, that vote will not carry over to the additional
ballot. It is the responsibility of the registered voter in the ballot pool to cast a vote again in the
additional ballot. To ensure a quorum is reached, if you do not want to vote affirmative or negative,
please cast an abstention.
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.
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 2010-14.1 Phase 1 of Balancing Authority
Reliability-based Controls: Reserves
BAL-002-2
Additional Ballot and Non-Binding Poll Results
Now Available

An additional ballot for BAL-002-2 – Disturbance Control Performance -Contingency Reserve for
Recovery from a Balancing Contingency Event and a non-binding poll of the associated Violation Risk
Factors and Violation Severity Levels concluded at 8 p.m. Eastern on Friday, October 3, 2013.
This standard achieved a quorum but did not receive sufficient affirmative votes for approval. Voting
statistics are listed below, and the Ballot Results page provides a link to the detailed results for the ballot.
Ballot

Non-Binding Poll

Quorum /Approval

Quorum/Supportive Opinions

79.94% / 46.73%

76.49% / 54.12%

Background information for this project can be found on the project page.
Next Steps

The drafting team will consider all comments received during the formal comment period to
determine the next steps.
For more information on the Standards Development Process, please refer to the Standard Processes
Manual.
For more information or assistance, please contact Darrel Richardson.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

NERC Standards

Newsroom • Site Map • Contact NERC

Advanced Search

Log In
Ballot Results

Ballot Name: Project 2010-14.1 BARC BAL-002-2
-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters
-Register

Ballot Period: 9/23/2014 - 10/3/2014
Ballot Type: $GGLWLRQDO
Total # Votes: 271
Total Ballot Pool: 339
Quorum: 79.94 % The Quorum has been reached

Home Page

Weighted Segment
46.73 %
Vote:
Ballot Results: The Ballot has Closed
Summary of Ballot Results

Affirmative

Negative

Negative
Vote
Ballot Segment
#
#
No
without a
Segment Pool
Weight Votes Fraction Votes Fraction Comment Abstain Vote
1Segment
1
2Segment
2
3Segment
3
4Segment
4
5Segment
5
6Segment
6
7Segment
7
8Segment
8
9Segment
9

89

1

29

0.475

32

0.525

0

14

14

10

0.9

3

0.3

6

0.6

0

0

1

75

1

25

0.5

25

0.5

0

10

15

23

1

8

0.444

10

0.556

0

3

2

71

1

26

0.591

18

0.409

0

8

19

53

1

17

0.515

16

0.485

0

9

11

2

0

0

0

0

0

0

0

2

5

0.3

1

0.1

2

0.2

0

0

2

3

0.1

0

0

1

0.1

0

0

2

https://standards.nerc.net/BallotResults.aspx?BallotGUID=8a5b553b-a2fd-49e3-898e-8c0e78b37972[10/6/2014 2:33:58 PM]

NERC Standards
10 Segment
10
Totals

8

0.6

3

0.3

3

0.3

0

2

0

339

6.9

112

3.225

113

3.675

0

46

68

Individual Ballot Pool Results

Ballot
Segment
1
1
1

Organization

Ameren Services
American Electric Power
Arizona Public Service Co.

Member
Eric Scott
Paul B Johnson
Robert Smith

1

Associated Electric Cooperative, Inc.

John Bussman

1
1
1
1
1
1

Austin Energy
Balancing Authority of Northern California
Baltimore Gas & Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.

James Armke
Kevin Smith
Christopher J Scanlon
Patricia Robertson
Donald S. Watkins
Tony Kroskey

1

Central Electric Power Cooperative

Michael B Bax

1
1

City of Tacoma, Department of Public
Chang G Choi
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
Daniel S Langston

Affirmative
Abstain

Negative

Negative

Affirmative

Jack Stamper

Negative

1

Colorado Springs Utilities

Paul Morland

Negative

1

Consolidated Edison Co. of New York

Christopher L de
Graffenried

Negative

1
1

CPS Energy
Dairyland Power Coop.

Richard Castrejana
Robert W. Roddy

Dayton Power & Light Co.

Hertzel Shamash

Negative

1

Dominion Virginia Power

Michael S Crowley

Negative

1

Duke Energy Carolina

Doug E Hils

Negative

1
1

El Paso Electric Company
Entergy Transmission

Dennis Malone
Oliver A Burke

https://standards.nerc.net/BallotResults.aspx?BallotGUID=8a5b553b-a2fd-49e3-898e-8c0e78b37972[10/6/2014 2:33:58 PM]

SUPPORTS THIRD
PARTY
COMMENTS (Seattle City
Light)
SUPPORTS THIRD
PARTY
COMMENTS Support
Comments from
(Northeast
Power
Coordinating
Council) NPPC
SUPPORTS THIRD
PARTY
COMMENTS (NPCC)

Abstain
Abstain

1

William J Smith

SUPPORTS THIRD
PARTY
COMMENTS (AECI)

Affirmative

Clark Public Utilities

FirstEnergy Corp.

SUPPORTS THIRD
PARTY
COMMENTS (AECI)

Abstain
Affirmative
Abstain
Affirmative
Affirmative
Abstain

1

1

NERC
Notes

SUPPORTS THIRD
PARTY
COMMENTS (PJM's
comments)
SUPPORTS THIRD
PARTY
COMMENTS PJM
SUPPORTS THIRD
PARTY
COMMENTS (Duke Energy)

Affirmative

Negative

SUPPORTS THIRD
PARTY
COMMENTS (Standards
Review
Committee
(SRC) of the
ISO/RTO Council
via PJM)

NERC Standards
1
1

Florida Power & Light Co.
Gainesville Regional Utilities

Mike O'Neil
Richard Bachmeier

1

Great River Energy

Gordon Pietsch

1

Hydro One Networks, Inc.

Ajay Garg

1

Hydro-Quebec TransEnergie

Martin Boisvert

1

Idaho Power Company
International Transmission Company
Holdings Corp
JDRJC Associates

Molly Devine

1
1

Affirmative
Affirmative

Negative

SUPPORTS THIRD
PARTY
COMMENTS (MRO NSRF and
ACES)

Negative

SUPPORTS THIRD
PARTY
COMMENTS (Hydro Quebec
TransEnergie)

Affirmative

Michael Moltane

Abstain

Jim D Cyrulewski

Abstain

1

KAMO Electric Cooperative

Walter Kenyon

1

Kansas City Power & Light Co.

Jennifer Flandermeyer

Negative
Affirmative

1

Lakeland Electric

Larry E Watt

Negative

1

Lincoln Electric System

Doug Bantam

Abstain

1

Long Island Power Authority

Robert Ganley

Negative

1
1

Los Angeles Department of Water & Power
Lower Colorado River Authority

John Burnett
Martyn Turner

Affirmative
Abstain

1

M & A Electric Power Cooperative

William Price

1
1

Manitoba Hydro
MEAG Power

Nazra S Gladu
Danny Dees

Affirmative
Affirmative

1

MidAmerican Energy Co.

Terry Harbour

Negative

1

Muscatine Power & Water

Andrew J Kurriger

1

N.W. Electric Power Cooperative, Inc.

Mark Ramsey

Negative

1

National Grid USA

Michael Jones

Negative

1

Nebraska Public Power District
New Brunswick Power Transmission
Corporation

Cole C Brodine

1

SUPPORTS THIRD
PARTY
COMMENTS (AECI)

Negative

SUPPORTS THIRD
PARTY
COMMENTS (Duke Energy)
SUPPORTS THIRD
PARTY
COMMENTS (PJM)

SUPPORTS THIRD
PARTY
COMMENTS (AECI)

SUPPORTS THIRD
PARTY
COMMENTS (MISO)
SUPPORTS THIRD
PARTY
COMMENTS (AECI)
SUPPORTS THIRD
PARTY
COMMENTS (National Grid
supports NPCC's
comments.)

Randy MacDonald

1

New York Power Authority

Bruce Metruck

Negative

1

Northeast Missouri Electric Power
Cooperative

Kevin White

Negative

1

Northern Indiana Public Service Co.

Julaine Dyke

Negative

1
1
1
1
1

Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission

Robert Mattey
Terri Pyle
Doug Peterchuck
Jen Fiegel
Brad Chase

SUPPORTS THIRD
PARTY
COMMENTS (NPCC)
SUPPORTS THIRD
PARTY
COMMENTS (AECI)
SUPPORTS THIRD
PARTY
COMMENTS (MISO)

Abstain
Abstain

SUPPORTS THIRD

https://standards.nerc.net/BallotResults.aspx?BallotGUID=8a5b553b-a2fd-49e3-898e-8c0e78b37972[10/6/2014 2:33:58 PM]

NERC Standards
1

Otter Tail Power Company

Daryl Hanson

1
1
1

Pacific Gas and Electric Company
Platte River Power Authority
Portland General Electric Co.

Bangalore Vijayraghavan
John C. Collins
John T Walker

1

Potomac Electric Power Co.

David Thorne

1

PowerSouth Energy Cooperative

Larry D Avery

Negative

Affirmative
Affirmative

Negative

SUPPORTS THIRD
PARTY
COMMENTS (PJM
Interconnection)
SUPPORTS THIRD
PARTY
COMMENTS (Comments
submitted on
behalf of PPL
NERC Registered
Entities)

1

PPL Electric Utilities Corp.

Brenda L Truhe

Negative

1

Public Service Company of New Mexico

Laurie Williams

Affirmative

1

Public Service Electric and Gas Co.

Kenneth D. Brown

1

Puget Sound Energy, Inc.

Denise M Lietz

1

Rochester Gas and Electric Corp.

John C. Allen

1
1
1
1

Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
Santee Cooper

Tim Kelley
Robert Kondziolka
Will Speer
Terry L Blackwell

Negative

Negative

Affirmative

Pawel Krupa

Negative

1

Sho-Me Power Electric Cooperative

Denise Stevens

Negative

1

Sierra Pacific Power Co.

Rich Salgo

Long T Duong

1
1
1

South Carolina Electric & Gas Co.
Southern California Edison Company
Southern Company Services, Inc.

Tom Hanzlik
Steven Mavis
Robert A. Schaffeld

1

Southern Illinois Power Coop.

William Hutchison

1

Southwest Transmission Cooperative, Inc.

John Shaver

1

Sunflower Electric Power Corporation

Noman Lee Williams

1

Tampa Electric Co.

Beth Young

1

Tennessee Valley Authority

Howell D Scott

1
1
1
1
1
1

Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.

Tracy Sliman
John Tolo
Jonathan Appelbaum
Allen Klassen
Lloyd A Linke
Gregory L Pieper

https://standards.nerc.net/BallotResults.aspx?BallotGUID=8a5b553b-a2fd-49e3-898e-8c0e78b37972[10/6/2014 2:33:58 PM]

SUPPORTS THIRD
PARTY
COMMENTS (NPCC)

Affirmative
Abstain

Seattle City Light

Snohomish County PUD No. 1

SUPPORTS THIRD
PARTY
COMMENTS PJM

Affirmative

1

1

PARTY
COMMENTS (MISO’s
comments)

Negative

SUPPORTS THIRD
PARTY
COMMENTS (Seattle City
Light's Paul
Haase's
Comment)
SUPPORTS THIRD
PARTY
COMMENTS (AECI)
SUPPORTS THIRD
PARTY
COMMENTS (Seattle City
Light)

Affirmative
Affirmative
Affirmative
Negative

SUPPORTS THIRD
PARTY
COMMENTS (ACES)

Affirmative
Negative

SUPPORTS THIRD
PARTY
COMMENTS (ACES)

Negative

SUPPORTS THIRD
PARTY
COMMENTS (SERC)

Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative

NERC Standards
2

Alberta Electric System Operator

2

California ISO

Ken A Gardner
Venkataramakrishnan
Vinnakota
Rich Vine

2

BC Hydro

Affirmative

2

Electric Reliability Council of Texas, Inc.

Cheryl Moseley

Negative

2

ISO New England, Inc.

Kathleen Goodman

Negative

2

Midwest ISO, Inc.

Marie Knox

Negative

2

New Brunswick System Operator

Alden Briggs

Affirmative
Affirmative

2

New York Independent System Operator

Gregory Campoli

Negative

2

PJM Interconnection, L.L.C.

stephanie monzon

Negative

2

Southwest Power Pool, Inc.

Charles H. Yeung

Negative

3
3
3
3
3

AEP
Alabama Power Company
Ameren Services
APS
Associated Electric Cooperative, Inc.

Michael E Deloach
Robert S Moore
Mark Peters
Steven Norris
Chris W Bolick

Atlantic City Electric Company

NICOLE BUCKMAN

Negative

3
3
3

Avista Corp.
BC Hydro and Power Authority
Bonneville Power Administration

Scott J Kinney
Pat G. Harrington
Rebecca Berdahl

Affirmative
Affirmative
Affirmative

3

Central Electric Power Cooperative

Adam M Weber

3
3
3
3
3
3

City of Austin dba Austin Energy
City of Bartow, Florida
City of Redding
City of Tallahassee
Colorado Springs Utilities
ComEd

Andrew Gallo
Matt Culverhouse
Bill Hughes
Bill R Fowler
Charles Morgan
John Bee

3

Consolidated Edison Co. of New York

Peter T Yost

3
3

Consumers Energy
CPS Energy

Richard Blumenstock
Jose Escamilla

Negative

Negative

SUPPORTS THIRD
PARTY
COMMENTS (NPCC)

Abstain
Abstain

Michael R. Mayer

Negative

3

Detroit Edison Company

Kent Kujala

Negative

3

Dominion Resources, Inc.

Connie B Lowe

Negative

3
3

El Paso Electric Company
Entergy

Tracy Van Slyke
Joel T Plessinger

https://standards.nerc.net/BallotResults.aspx?BallotGUID=8a5b553b-a2fd-49e3-898e-8c0e78b37972[10/6/2014 2:33:58 PM]

SUPPORTS THIRD
PARTY
COMMENTS (AECI)

Abstain

Delmarva Power & Light Co.

Cindy E Stewart

SUPPORTS THIRD
PARTY
COMMENTS (PJM
Interconnection)

Abstain
Affirmative
Affirmative
Affirmative

3

FirstEnergy Corp.

SUPPORTS THIRD
PARTY
COMMENTS (IRC/SRC &
NPCC/RSC)
SUPPORTS THIRD
PARTY
COMMENTS (SRC)
COMMENT
RECEIVED

Affirmative
Affirmative

3

3

COMMENT
RECEIVED
COMMENT
RECEIVED
COMMENT
RECEIVED

Negative

SUPPORTS THIRD
PARTY
COMMENTS (comments
submitted by
PJM
Interconnection)
SUPPORTS THIRD
PARTY
COMMENTS (MISO)
SUPPORTS THIRD
PARTY
COMMENTS (Supports PJMs
comments)

SUPPORTS THIRD
PARTY
COMMENTS Standards
Review
Committee

NERC Standards
(SRC) of the
ISO/RTO Council
3

Florida Municipal Power Agency

Joe McKinney

3

Florida Power Corporation

Lee Schuster

3

Gainesville Regional Utilities

Kenneth Simmons

3

Great River Energy

Brian Glover

3
3
3
3
3

Hydro One Networks, Inc.
Imperial Irrigation District
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.

David Kiguel
Jesus S. Alcaraz
Garry Baker
Theodore J Hilmes
Charles Locke

3

Kissimmee Utility Authority

Gregory D Woessner

3
3

Lakeland Electric
Lincoln Electric System

Mace D Hunter
Jason Fortik

Affirmative
Negative

SUPPORTS THIRD
PARTY
COMMENTS (Duke Energy)

Affirmative
Negative

SUPPORTS THIRD
PARTY
COMMENTS (ACES)

Negative

SUPPORTS THIRD
PARTY
COMMENTS (Seminole
Electric and
Duke Energy)

Affirmative
Abstain

3

Louisville Gas and Electric Co.

Charles A. Freibert

Negative

3

M & A Electric Power Cooperative

Stephen D Pogue

Negative

3
3
3
3

Manitoba Hydro
MEAG Power
Modesto Irrigation District
Muscatine Power & Water

Greg C. Parent
Roger Brand
Jack W Savage
John S Bos

3

National Grid USA

Brian E Shanahan

Negative

3

Nebraska Public Power District

Tony Eddleman

Negative

3

New York Power Authority

David R Rivera

Negative

3

Northeast Missouri Electric Power
Cooperative

Skyler Wiegmann

Negative

3

NW Electric Power Cooperative, Inc.

David McDowell

Negative

3
3
3
3
3

Oklahoma Gas and Electric Co.
Omaha Public Power District
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company

Donald Hargrove
Blaine R. Dinwiddie
Ballard K Mutters
Thomas T Lyons
John H Hagen

3

PacifiCorp

Dan Zollner

3
3
3

Platte River Power Authority
PNM Resources
Portland General Electric Co.

Terry L Baker
Michael Mertz
Thomas G Ward

SUPPORTS THIRD
PARTY
COMMENTS (PPL NERC
Registered
Affiliates.)
SUPPORTS THIRD
PARTY
COMMENTS (AECI)

Affirmative
Affirmative

SUPPORTS THIRD
PARTY
COMMENTS (NPCC RSC)
SUPPORTS THIRD
PARTY
COMMENTS (Southwest
Power Pool (SPP)
comments)
SUPPORTS THIRD
PARTY
COMMENTS (NPCC
Comments)
SUPPORTS THIRD
PARTY
COMMENTS (AECI)
SUPPORTS THIRD
PARTY
COMMENTS (AECI)

Abstain
Abstain
Affirmative
Abstain
Affirmative
Negative

SUPPORTS THIRD
PARTY
COMMENTS MISO

Affirmative
Affirmative
Affirmative
SUPPORTS THIRD

https://standards.nerc.net/BallotResults.aspx?BallotGUID=8a5b553b-a2fd-49e3-898e-8c0e78b37972[10/6/2014 2:33:58 PM]

NERC Standards
3

Potomac Electric Power Co.

Mark Yerger

Negative

3

Public Service Electric and Gas Co.

Jeffrey Mueller

Negative

3
3
3
3

Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper

Erin Apperson
James Leigh-Kendall
John T. Underhill
James M Poston

Affirmative
Affirmative
Affirmative
Affirmative

3

Seattle City Light

Dana Wheelock

Negative

3

Seminole Electric Cooperative, Inc.

James R Frauen

Negative

3

Sho-Me Power Electric Cooperative

Jeff L Neas

Negative

3

Snohomish County PUD No. 1

Mark Oens

Negative

3
3
3
3
3
3

South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Westar Energy

Hubert C Young
Travis Metcalfe
Ronald L. Donahey
Ian S Grant
Janelle Marriott
Bo Jones

3

Wisconsin Electric Power Marketing

James R Keller

3
4
4
4
4
4

Xcel Energy, Inc.
Self
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
City of Austin dba Austin Energy
City of New Smyrna Beach Utilities
Commission
City of Redding

Michael Ibold
Herb Schrayshuen
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Reza Ebrahimian

Affirmative
Abstain

Tim Beyrle

Affirmative

Nicholas Zettel

Affirmative

4
4

4

City Utilities of Springfield, Missouri

John Allen

4
4
4

Consumers Energy Company
Flathead Electric Cooperative
Florida Municipal Power Agency

Tracy Goble
Russ Schneider
Frank Gaffney

SUPPORTS THIRD
PARTY
COMMENTS (Seattle City
Light's Paul
Haase's
Comment)
SUPPORTS THIRD
PARTY
COMMENTS (Seminole
Electric
Cooperative)
SUPPORTS THIRD
PARTY
COMMENTS (AECI)
SUPPORTS THIRD
PARTY
COMMENTS (Seattle City
Light)

Affirmative
Affirmative

Abstain
Abstain
Negative

SUPPORTS THIRD
PARTY
COMMENTS (MISO)

Affirmative
Affirmative
Affirmative

Negative

SUPPORTS THIRD
PARTY
COMMENTS (SPP Standards
Group)

Abstain
Abstain
Affirmative

4

Georgia System Operations Corporation

Guy Andrews

Negative

4

Madison Gas and Electric Co.

Joseph DePoorter

Negative

4

Modesto Irrigation District

Spencer Tacke

Negative

https://standards.nerc.net/BallotResults.aspx?BallotGUID=8a5b553b-a2fd-49e3-898e-8c0e78b37972[10/6/2014 2:33:58 PM]

PARTY
COMMENTS (PJM
Interconnection)
SUPPORTS THIRD
PARTY
COMMENTS (PJM)

SUPPORTS THIRD
PARTY
COMMENTS (SERC OC
Review Group)
SUPPORTS THIRD
PARTY
COMMENTS (MRO NSRF)
COMMENT
RECEIVED
SUPPORTS THIRD
PARTY
COMMENTS -

NERC Standards
4

Ohio Edison Company

Douglas Hohlbaugh

4

Public Utility District No. 1 of Douglas
County

Henry E. LuBean

4

Public Utility District No. 1 of Snohomish
County

John D Martinsen

4

Sacramento Municipal Utility District

Mike Ramirez

Negative

Negative

SUPPORTS THIRD
PARTY
COMMENTS (Seattle City
Light)

Affirmative

4

Seattle City Light

Hao Li

Negative

4

Seminole Electric Cooperative, Inc.

Steven R Wallace

Negative

4

Tacoma Public Utilities

Keith Morisette

4

Utility Services, Inc.

Brian Evans-Mongeon

Negative

4

Wisconsin Energy Corp.

Anthony P Jankowski

Negative

5
5
5
5
5

AEP Service Corp.
Amerenue
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
BC Hydro and Power Authority

Brock Ondayko
Sam Dwyer
Scott Takinen
Matthew Pacobit
Clement Ma

5

Boise-Kuna Irrigation District/dba Lucky
peak power plant project

Mike D Kukla

5

Bonneville Power Administration

Francis J. Halpin

5

Brazos Electric Power Cooperative, Inc.

Shari Heino

5
5
5
5
5

City of Austin dba Austin Energy
City of Redding
City of Tallahassee
City Water, Light & Power of Springfield
Colorado Springs Utilities

Jeanie Doty
Paul A. Cummings
Karen Webb
Steve Rose
Michael Shultz

5

Consolidated Edison Co. of New York

Wilket (Jack) Ng

5
5

Consumers Energy Company
Dairyland Power Coop.

David C Greyerbiehl
Tommy Drea

5

Dominion Resources, Inc.

Mike Garton

Negative

5

Duke Energy

Dale Q Goodwine

Negative

5
5
5

Electric Power Supply Association
Entergy Services, Inc.
Exelon Nuclear

John R Cashin
Tracey Stubbs
Mark F Draper

https://standards.nerc.net/BallotResults.aspx?BallotGUID=8a5b553b-a2fd-49e3-898e-8c0e78b37972[10/6/2014 2:33:58 PM]

(Standards
Review
Committee
(SRC) of the
ISO/RTO Council
via PJM)

SUPPORTS THIRD
PARTY
COMMENTS (Seattle City
Light's Paul
Haase's
Comment)
SUPPORTS THIRD
PARTY
COMMENTS (Seminole
Electric
Cooperative
comments
submitted by
Maryclaire
Yatsko)

Affirmative
SUPPORTS THIRD
PARTY
COMMENTS (NPCC)
SUPPORTS THIRD
PARTY
COMMENTS (MISO)

Affirmative
Affirmative
Affirmative
Negative

SUPPORTS THIRD
PARTY
COMMENTS (SCL comments)

Affirmative
Negative

SUPPORTS THIRD
PARTY
COMMENTS (ACES)

Abstain
Affirmative
Affirmative

Negative

SUPPORTS THIRD
PARTY
COMMENTS NPCC and NYISO

Abstain

Affirmative
Abstain

SUPPORTS THIRD
PARTY
COMMENTS (PJM)
SUPPORTS THIRD
PARTY
COMMENTS (Duke Energy)

NERC Standards

5

FirstEnergy Solutions

Kenneth Dresner

Negative

5
5

Florida Municipal Power Agency
Gainesville Regional Utilities

David Schumann
Karen C Alford

Affirmative

5

Great River Energy

Preston L Walsh

5
5
5

Imperial Irrigation District
JEA
Kansas City Power & Light Co.

Marcela Y Caballero
John J Babik
Brett Holland

5

Lakeland Electric

James M Howard

5
5
5

Lincoln Electric System
Los Angeles Department of Water & Power
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.

Dennis Florom
Kenneth Silver
S N Fernando

Abstain
Affirmative
Affirmative

David Gordon

Abstain

5
5
5

Steven Grego
Neil D Hammer

Negative

Negative

SUPPORTS THIRD
PARTY
COMMENTS (Duke Energy)

Affirmative

Muscatine Power & Water

Mike Avesing

Negative

5

Nebraska Public Power District

Don Schmit

Negative

5

New York Power Authority

Wayne Sipperly

Negative

5
5
5
5
5
5
5
5
5
5

NextEra Energy
Northern Indiana Public Service Co.
Oglethorpe Power Corporation
Oklahoma Gas and Electric Co.
Omaha Public Power District
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PowerSouth Energy Cooperative

Allen D Schriver
William O. Thompson
Bernard Johnson
Henry L Staples
Mahmood Z. Safi
Richard K Kinas
Bonnie Marino-Blair
Roland Thiel
Matt E. Jastram
Tim Hattaway

SUPPORTS THIRD
PARTY
COMMENTS (NSRF
comments)
SUPPORTS THIRD
PARTY
COMMENTS (SPP RTO)
SUPPORTS THIRD
PARTY
COMMENTS (NPCC
comments)

Affirmative

Abstain

Affirmative
Affirmative
Affirmative

5

PPL Generation LLC

Annette M Bannon

Negative

5

PSEG Fossil LLC

Tim Kucey

Negative

Michiko Sell

Affirmative

5
5
5
5

Public Utility District No. 2 of Grant County,
Washington
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper

Lynda Kupfer
Susan Gill-Zobitz
William Alkema
Lewis P Pierce

Affirmative
Affirmative
Affirmative
Affirmative

5

Seattle City Light

Michael J. Haynes

Negative

https://standards.nerc.net/BallotResults.aspx?BallotGUID=8a5b553b-a2fd-49e3-898e-8c0e78b37972[10/6/2014 2:33:58 PM]

SUPPORTS THIRD
PARTY
COMMENTS (MRO NSRF
ACES)

Affirmative
Affirmative

5

5

SUPPORTS THIRD
PARTY
COMMENTS (Standards
Review
Committee
(SRC) of the
ISO/RTO Council
via PJM)

SUPPORTS THIRD
PARTY
COMMENTS (PPL NERC
Registered
Affiliates)
SUPPORTS THIRD
PARTY
COMMENTS (PJM comments)

SUPPORTS THIRD
PARTY
COMMENTS (Haase, SEattle)

NERC Standards

5

Seminole Electric Cooperative, Inc.

Brenda K. Atkins

Negative

5

Snohomish County PUD No. 1

Sam Nietfeld

Negative

5
5
5
5
5
5

South Carolina Electric & Gas Co.
Southern California Edison Company
Southern Company Generation
Tacoma Power
Tampa Electric Co.
Tenaska, Inc.

Edward Magic
Denise Yaffe
William D Shultz
Chris Mattson
RJames Rocha
Scott M. Helyer

Affirmative
Affirmative
Affirmative
Affirmative

5

Tennessee Valley Authority

David Thompson

Negative

5
5
5
5

Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
U.S. Bureau of Reclamation
Westar Energy

Mark Stein
Melissa Kurtz
Martin Bauer
Bryan Taggart

5

Wisconsin Electric Power Co.

Linda Horn

5
6
6
6

Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
APS

Liam Noailles
Edward P. Cox
Jennifer Richardson
Randy A. Young

6

Associated Electric Cooperative, Inc.

Brian Ackermann

6
6
6
6

Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC

Brenda S. Anderson
Lisa Martin
Marvin Briggs
Robert Hirchak

Abstain
Negative

Negative

Negative

6

Con Edison Company of New York

David Balban

Negative

6

Constellation Energy Commodities Group

David J Carlson

6

Dominion Resources, Inc.

Louis S. Slade

Negative

6

Duke Energy

Greg Cecil

Negative

6

Entergy Services, Inc.

Terri F Benoit

6
6
6

Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.

Richard L. Montgomery
Thomas Washburn
Silvia P Mitchell

SUPPORTS THIRD
PARTY
COMMENTS (AECI)

Affirmative
Abstain
Affirmative
Affirmative

Shannon Fair

Kevin Querry

SUPPORTS THIRD
PARTY
COMMENTS (MISO)

Abstain
Affirmative
Affirmative

Colorado Springs Utilities

FirstEnergy Solutions

COMMENT
RECEIVED

Abstain

6

6

SUPPORTS THIRD
PARTY
COMMENTS (Posted by
Seminole
Corporate
Compliance)
SUPPORTS THIRD
PARTY
COMMENTS (Seattle City
Light)

SUPPORTS THIRD
PARTY
COMMENTS ((Northeast
Power
Coordinating
Council) NPPC)
SUPPORTS THIRD
PARTY
COMMENTS (NPCC)

Abstain

Negative

SUPPORTS THIRD
PARTY
COMMENTS (PJM)
SUPPORTS THIRD
PARTY
COMMENTS (Duke Energy)
SUPPORTS THIRD
PARTY
COMMENTS (Standards
Review
Committee
(SRC) of the
ISO/RTO Council
via PJM)

Affirmative
Affirmative
SUPPORTS THIRD
PARTY

https://standards.nerc.net/BallotResults.aspx?BallotGUID=8a5b553b-a2fd-49e3-898e-8c0e78b37972[10/6/2014 2:33:58 PM]

NERC Standards
6

Great River Energy

Donna Stephenson

6
6

Imperial Irrigation District
Kansas City Power & Light Co.

Cathy Bretz
Jessica L Klinghoffer

Negative

Affirmative

6

Lakeland Electric

Paul Shipps

6
6
6
6
6

Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Energy
Manitoba Hydro
Modesto Irrigation District

Eric Ruskamp
Brad Packer
Brenda Hampton
Blair Mukanik
James McFall

6

Muscatine Power & Water

John Stolley

Negative

6

New York Power Authority

Saul Rojas

Negative

6
6
6
6
6
6
6

Northern Indiana Public Service Co.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
Power Generation Services, Inc.
Powerex Corp.

Joseph O'Brien
Douglas Collins
Kelly Cumiskey
Carol Ballantine
Ty Bettis
Stephen C Knapp
Daniel W. O'Hearn

Negative

Affirmative

Elizabeth Davis

Negative

6

PSEG Energy Resources & Trade LLC

Peter Dolan

Negative

6
6
6
6

Public Utility District No. 1 of Chelan County Hugh A. Owen
Sacramento Municipal Utility District
Diane Enderby
Salt River Project
Steven J Hulet
Santee Cooper
Michael Brown

6

Seattle City Light

Dennis Sismaet

Negative

6

Seminole Electric Cooperative, Inc.

Trudy S. Novak

Negative

6

Snohomish County PUD No. 1

Kenn Backholm

Negative

6

Lujuanna Medina

Affirmative

John J. Ciza

Affirmative

6
6

Southern California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.

Michael C Hill
Benjamin F Smith II

6

Tennessee Valley Authority

Marjorie S. Parsons

6

Westar Energy
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
EnerVision, Inc.
Steel Manufacturers Association

Grant L Wilkerson

6
7
7

https://standards.nerc.net/BallotResults.aspx?BallotGUID=8a5b553b-a2fd-49e3-898e-8c0e78b37972[10/6/2014 2:33:58 PM]

SUPPORTS THIRD
PARTY
COMMENTS (PPL NERC
Registered
Affiliates)
SUPPORTS THIRD
PARTY
COMMENTS (PJM)

Abstain
Affirmative
Affirmative
Affirmative

Negative
Abstain

Peter H Kinney
David F Lemmons
Thomas W Siegrist
James Brew

SUPPORTS THIRD
PARTY
COMMENTS (MRO NSRF)
SUPPORTS THIRD
PARTY
COMMENTS NPCC RSC
Comments

Abstain
Abstain

PPL EnergyPlus LLC

6

SUPPORTS THIRD
PARTY
COMMENTS (Duke Energy)

Abstain
Affirmative
Abstain
Affirmative

6

6

COMMENTS (MRO and ACES)

Affirmative

SUPPORTS THIRD
PARTY
COMMENTS (Paul Haase)
SUPPORTS THIRD
PARTY
COMMENTS (Seminole
Electric
Cooperative's
Corporate
Compliance
department)
SUPPORTS THIRD
PARTY
COMMENTS (Seattle City
Light)

COMMENT
RECEIVED

NERC Standards

8

Roger C Zaklukiewicz

Negative

8
8
8

Robert Blohm
Debra R Warner
Howard F. Illian

Affirmative

Debra R Warner
Energy Mark, Inc.

8

Volkmann Consulting, Inc.

Terry Volkmann

Negative

9

Commonwealth of Massachusetts
Department of Public Utilities

Donald Nelson

Negative

9
9
10
10

Gainesville Regional Utilities
National Association of Regulatory Utility
Commissioners
Florida Reliability Coordinating Council
Midwest Reliability Organization

SUPPORTS THIRD
PARTY
COMMENTS (NPCC)

SUPPORTS THIRD
PARTY
COMMENTS (MRO NSRF)
SUPPORTS THIRD
PARTY
COMMENTS (NPCC)

Norman Harryhill
Diane J. Barney
Linda C Campbell
Russel Mountjoy

Abstain
Affirmative

10

New York State Reliability Council

Alan Adamson

Negative

10

Northeast Power Coordinating Council

Guy V. Zito

Negative

10

ReliabilityFirst Corporation

Anthony E Jablonski

10

SERC Reliability Corporation

Carter B Edge

10
10

Texas Reliability Entity, Inc.
Western Electricity Coordinating Council

Donald G Jones
Steven L. Rueckert

SUPPORTS THIRD
PARTY
COMMENTS (NPCC)
COMMENT
RECEIVED

Abstain
Negative

COMMENT
RECEIVED SERC Operating
Committee

Affirmative
Affirmative

Legal and Privacy : 404.446.2560 voice : 404.467.0474 fax : 3353 Peachtree Road, N.E. : Suite 600, North Tower : Atlanta, GA 30326
Washington Office: 1325 G Street, N.W. : Suite 600 : Washington, DC 20005-3801

Copyright © 2014 by the North American Electric Reliability Corporation. : All rights reserved.
A New Jersey Nonprofit Corporation

https://standards.nerc.net/BallotResults.aspx?BallotGUID=8a5b553b-a2fd-49e3-898e-8c0e78b37972[10/6/2014 2:33:58 PM]

Non-Binding Poll Results

Project 2010-14.1 Phase 1 of Balancing Authority
Reliability-based Controls: Reserves
BAL-002-2
Non-Binding Poll Results

Non-Binding Poll
Project 2010-14.1 BARC BAL-002-2
Name:
Poll Period: 9/23/2014 - 10/3/2014
Total # Opinions: 244
Total Ballot Pool: 319
76.49% of those who registered to participate provided an opinion or an
Summaray Results: abstention; 54.12% of those who provided an opinion indicated support for
the VRFs and VSLs.
Individual Ballot Pool Results

Segment

Organization

Member

1
1

Ameren Services
American Electric Power

Eric Scott
Paul B Johnson

1

Arizona Public Service Co.

Robert Smith

1

Associated Electric Cooperative, Inc.

John Bussman

1
1
1
1
1

Austin Energy
Balancing Authority of Northern California
BC Hydro and Power Authority
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.

James Armke
Kevin Smith
Patricia Robertson
Donald S. Watkins
Tony Kroskey

1

1
1

Central Electric Power Cooperative

Michael B Bax

City of Tacoma, Department of Public
Chang G Choi
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
Daniel S Langston

Opinions

NERC
Notes

Abstain
Abstain

Negative

SUPPORTS
THIRD PARTY
COMMENTS (AECI)

Abstain
Affirmative
Abstain
Affirmative
Abstain
Negative

Affirmative
Affirmative

SUPPORTS
THIRD PARTY
COMMENTS (AECI)

1

Clark Public Utilities

Jack Stamper

Negative

1

Colorado Springs Utilities

Paul Morland

Negative

1

Consolidated Edison Co. of New York

Christopher L de
Graffenried

Negative

1
1
1

CPS Energy
Dairyland Power Coop.
Dominion Virginia Power

Richard Castrejana
Robert W. Roddy
Michael S Crowley

1

Duke Energy Carolina

Doug E Hils

1

El Paso Electric Company

Dennis Malone

1

Entergy Transmission

Oliver A Burke

1

FirstEnergy Corp.

William J Smith

1
1

Florida Power & Light Co.
Gainesville Regional Utilities

Mike O'Neil
Richard Bachmeier

1

Great River Energy

Gordon Pietsch

1

Hydro One Networks, Inc.

Ajay Garg

1

Hydro-Quebec TransEnergie

Martin Boisvert

1

Idaho Power Company
International Transmission Company
Holdings Corp
JDRJC Associates

Molly Devine

1
1

Non-Binding Poll Results
Project 2010-14.1 BAL-002-2 | October 2014

SUPPORTS
THIRD PARTY
COMMENTS (Seattle City
Light)
SUPPORTS
THIRD PARTY
COMMENTS NPCC
SUPPORTS
THIRD PARTY
COMMENTS (NPCC)

Abstain
Abstain
Abstain

Negative

SUPPORTS
THIRD PARTY
COMMENTS (Duke
Energy)

Affirmative

Negative

SUPPORTS
THIRD PARTY
COMMENTS (Standards
Review
Committee
(SRC) of the
ISO/RTO
Council via
PJM)

Affirmative
Affirmative

Negative

SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF
and ACES)

Negative

SUPPORTS
THIRD PARTY
COMMENTS (Hydro
Quebec
TransEnergie)

Affirmative

Michael Moltane

Abstain

Jim D Cyrulewski

Abstain

2

1

KAMO Electric Cooperative

Walter Kenyon

1

Kansas City Power & Light Co.

Jennifer Flandermeyer

1

Lakeland Electric

Larry E Watt

1
1
1
1

Lincoln Electric System
Doug Bantam
Long Island Power Authority
Robert Ganley
Los Angeles Department of Water & Power John Burnett
Lower Colorado River Authority
Martyn Turner

1

M & A Electric Power Cooperative

William Price

1
1

Manitoba Hydro
MEAG Power

Nazra S Gladu
Danny Dees

1

MidAmerican Energy Co.

Terry Harbour

1

Muscatine Power & Water

Andrew J Kurriger

Negative
Affirmative

Negative

SUPPORTS
THIRD PARTY
COMMENTS (Duke
Energy)

Abstain
Abstain
Abstain
Abstain
Negative

SUPPORTS
THIRD PARTY
COMMENTS (AECI)

Affirmative
Affirmative
Negative

1

N.W. Electric Power Cooperative, Inc.

Mark Ramsey

Negative

1

National Grid USA

Michael Jones

Negative

1

Nebraska Public Power District

Cole C Brodine

1

New Brunswick Power Transmission
Corporation

Randy MacDonald

1

New York Power Authority

Bruce Metruck

Negative

1

Northeast Missouri Electric Power
Cooperative

Kevin White

Negative

1

Northern Indiana Public Service Co.

Julaine Dyke

Negative

Non-Binding Poll Results
Project 2010-14.1 BAL-002-2 | October 2014

SUPPORTS
THIRD PARTY
COMMENTS (AECI)

SUPPORTS
THIRD PARTY
COMMENTS (MISO)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (National
Grid supports
NPCC's
comments.)

SUPPORTS
THIRD PARTY
COMMENTS (See NPCC
Comments)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (MISO)

3

1

Ohio Valley Electric Corp.

Robert Mattey

1
1

Oklahoma Gas and Electric Co.
Omaha Public Power District

Terri Pyle
Doug Peterchuck

1

Orlando Utilities Commission

Brad Chase

1

Otter Tail Power Company

Daryl Hanson

1

Pacific Gas and Electric Company

Bangalore Vijayraghavan

1
1

Platte River Power Authority
Portland General Electric Co.

John C. Collins
John T Walker

1

PowerSouth Energy Cooperative

Larry D Avery

1

PPL Electric Utilities Corp.

Brenda L Truhe

1
1
1
1

Public Service Company of New Mexico
Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Sacramento Municipal Utility District

Laurie Williams
Kenneth D. Brown
Denise M Lietz
Tim Kelley

1

Salt River Project

Robert Kondziolka

1

San Diego Gas & Electric

Will Speer

1
1

Santee Cooper
Seattle City Light

Terry L Blackwell
Pawel Krupa

1

Sho-Me Power Electric Cooperative

Denise Stevens

1

Sierra Pacific Power Co.

Rich Salgo

1

Snohomish County PUD No. 1

Long T Duong

1
1
1

South Carolina Electric & Gas Co.
Southern California Edison Company
Southern Company Services, Inc.

Tom Hanzlik
Steven Mavis
Robert A. Schaffeld

1

Southern Illinois Power Coop.

1

Southwest Transmission Cooperative, Inc. John Shaver

Non-Binding Poll Results
Project 2010-14.1 BAL-002-2 | October 2014

William Hutchison

Abstain
Abstain

Negative

SUPPORTS
THIRD PARTY
COMMENTS (MISO’s
comments)

Abstain
Affirmative

Negative

SUPPORTS
THIRD PARTY
COMMENTS (Comments
submitted on
behalf of PPL
NERC
Registered
Entities)

Affirmative
Abstain
Affirmative
Affirmative

Affirmative
Abstain
Negative

SUPPORTS
THIRD PARTY
COMMENTS (AECI)

Negative

SUPPORTS
THIRD PARTY
COMMENTS (Seattle City
Light)

Affirmative
Affirmative
Affirmative
Negative

SUPPORTS
THIRD PARTY
COMMENTS (ACES)

Affirmative

4

1

Sunflower Electric Power Corporation

Noman Lee Williams

1

Tampa Electric Co.

Beth Young

1

Tennessee Valley Authority

Howell D Scott

1
1
1
1
1

Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration

Tracy Sliman
John Tolo
Jonathan Appelbaum
Allen Klassen
Lloyd A Linke

1

Xcel Energy, Inc.

Negative

SUPPORTS
THIRD PARTY
COMMENTS (ACES)

Negative

SUPPORTS
THIRD PARTY
COMMENTS (SERC)

Affirmative
Affirmative
Affirmative
Abstain
Affirmative

Gregory L Pieper

2

BC Hydro

2

California ISO

Venkataramakrishnan
Vinnakota
Rich Vine

2

Electric Reliability Council of Texas, Inc.

Cheryl Moseley

Negative

2

Midwest ISO, Inc.

Marie Knox

Negative

2

New Brunswick System Operator

Alden Briggs

2

New York Independent System Operator

Gregory Campoli

2

PJM Interconnection, L.L.C.

Affirmative

Negative
Abstain

Southwest Power Pool, Inc.

Charles H. Yeung

3

AEP

Michael E Deloach

3
3

Alabama Power Company
Ameren Services

Robert S Moore
Mark Peters

3

APS

Steven Norris

3

Associated Electric Cooperative, Inc.

Chris W Bolick

3
3
3

Avista Corp.
BC Hydro and Power Authority
Bonneville Power Administration

Scott J Kinney
Pat G. Harrington
Rebecca Berdahl

3

Central Electric Power Cooperative

Adam M Weber

3
3
3

City of Austin dba Austin Energy
City of Redding
City of Tallahassee

Andrew Gallo
Bill Hughes
Bill R Fowler

3

Colorado Springs Utilities

Charles Morgan

3

Consolidated Edison Co. of New York

Peter T Yost

COMMENT
RECEIVED
COMMENT
RECEIVED

Abstain

stephanie monzon

2

Non-Binding Poll Results
Project 2010-14.1 BAL-002-2 | October 2014

Abstain

SUPPORTS
THIRD PARTY
COMMENTS (SRC)

Affirmative
Abstain

Affirmative
Abstain
Affirmative
Negative

SUPPORTS
THIRD PARTY
COMMENTS (AECI)

Abstain
Affirmative
Affirmative
Negative

SUPPORTS
THIRD PARTY

5

COMMENTS (NPCC)
3
3

Consumers Energy
CPS Energy

Richard Blumenstock
Jose Escamilla

3

Detroit Edison Company

Kent Kujala

3

Dominion Resources, Inc.

Connie B Lowe

3

El Paso Electric Company

Tracy Van Slyke

3

Entergy

Joel T Plessinger

3

FirstEnergy Corp.

Cindy E Stewart

3

Florida Municipal Power Agency

Joe McKinney

3

Florida Power Corporation

Lee Schuster

3

Gainesville Regional Utilities

Kenneth Simmons

3

Great River Energy

Brian Glover

3

Hydro One Networks, Inc.

David Kiguel

3

Imperial Irrigation District

Jesus S. Alcaraz

3

JEA

Garry Baker

3

KAMO Electric Cooperative

Theodore J Hilmes

3

Kansas City Power & Light Co.

Charles Locke

3
3
3

Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System

Gregory D Woessner
Mace D Hunter
Jason Fortik

3

Louisville Gas and Electric Co.

Charles A. Freibert

3

M & A Electric Power Cooperative

Stephen D Pogue

3
3

Manitoba Hydro
MEAG Power

Greg C. Parent
Roger Brand

3

Modesto Irrigation District

Jack W Savage

3

Muscatine Power & Water

John S Bos

Non-Binding Poll Results
Project 2010-14.1 BAL-002-2 | October 2014

Abstain
Abstain
Negative

SUPPORTS
THIRD PARTY
COMMENTS (MISO)

Abstain

Negative

SUPPORTS
THIRD PARTY
COMMENTS Standards
Review
Committee
(SRC) of the
ISO/RTO
Council

Affirmative

Negative

SUPPORTS
THIRD PARTY
COMMENTS (Duke
Energy)

Affirmative
Negative

SUPPORTS
THIRD PARTY
COMMENTS (ACES)

Abstain
Affirmative
Abstain

Negative

SUPPORTS
THIRD PARTY
COMMENTS (AECI)

Affirmative
Affirmative

6

3

National Grid USA

Brian E Shanahan

3

Nebraska Public Power District

Tony Eddleman

Negative
Abstain

3

New York Power Authority

David R Rivera

Negative

3

Northeast Missouri Electric Power
Cooperative

Skyler Wiegmann

Negative

3

NW Electric Power Cooperative, Inc.

David McDowell

Negative

3
3
3
3
3

Oklahoma Gas and Electric Co.
Omaha Public Power District
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company

Donald Hargrove
Blaine R. Dinwiddie
Ballard K Mutters
Thomas T Lyons
John H Hagen

3

PacifiCorp

Dan Zollner

3
3
3
3
3
3
3
3
3

Platte River Power Authority
PNM Resources
Portland General Electric Co.
Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light

Terry L Baker
Michael Mertz
Thomas G Ward
Jeffrey Mueller
Erin Apperson
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock

SUPPORTS
THIRD PARTY
COMMENTS (NPCC
Comments)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)

Abstain
Abstain
Abstain
Abstain
Affirmative
Negative

SUPPORTS
THIRD PARTY
COMMENTS MISO

Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain

3

Seminole Electric Cooperative, Inc.

James R Frauen

Negative

3

Sho-Me Power Electric Cooperative

Jeff L Neas

Negative

3

Snohomish County PUD No. 1

Mark Oens

Negative

Non-Binding Poll Results
Project 2010-14.1 BAL-002-2 | October 2014

SUPPORTS
THIRD PARTY
COMMENTS (NPCC RSC)

SUPPORTS
THIRD PARTY
COMMENTS (Seminole
Electric
Cooperative)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (Seattle City
Light)

7

3
3

South Carolina Electric & Gas Co.
Tacoma Public Utilities

Hubert C Young
Travis Metcalfe

3

Tampa Electric Co.

Ronald L. Donahey

3

Tennessee Valley Authority

Ian S Grant

3
3

Tri-State G & T Association, Inc.
Westar Energy

Janelle Marriott
Bo Jones

3

Wisconsin Electric Power Marketing

James R Keller

3
4
4

Xcel Energy, Inc.
Self
Alliant Energy Corp. Services, Inc.

Michael Ibold
Herb Schrayshuen
Kenneth Goldsmith

4

American Municipal Power

Kevin Koloini

4
4

Blue Ridge Power Agency
City of Austin dba Austin Energy
City of New Smyrna Beach Utilities
Commission
City of Redding

Duane S Dahlquist
Reza Ebrahimian

Affirmative
Abstain

Tim Beyrle

Affirmative

Nicholas Zettel

Affirmative

4
4

4

City Utilities of Springfield, Missouri

John Allen

4
4
4

Consumers Energy Company
Flathead Electric Cooperative
Florida Municipal Power Agency

Tracy Goble
Russ Schneider
Frank Gaffney

4

Georgia System Operations Corporation

Guy Andrews

4

Madison Gas and Electric Co.

Joseph DePoorter

4

Modesto Irrigation District

Spencer Tacke

4

Ohio Edison Company

Douglas Hohlbaugh

4

Public Utility District No. 1 of Douglas
County

Henry E. LuBean

4

Public Utility District No. 1 of Snohomish
County

Non-Binding Poll Results
Project 2010-14.1 BAL-002-2 | October 2014

John D Martinsen

Affirmative
Affirmative

Abstain
Abstain
Affirmative
Affirmative
Affirmative

Negative

SUPPORTS
THIRD PARTY
COMMENTS (SPP
Standards
Group)

Abstain
Abstain
Affirmative

Negative

SUPPORTS
THIRD PARTY
COMMENTS (SERC OC
Review
Group)

Abstain

Negative

SUPPORTS
THIRD PARTY
COMMENTS (Standards
Review
Committee
(SRC) of the
ISO/RTO
Council via
PJM)

Negative

SUPPORTS
THIRD PARTY
COMMENTS (Seattle City
Light)

8

4
4

Sacramento Municipal Utility District
Seattle City Light

Mike Ramirez
Hao Li

4

Seminole Electric Cooperative, Inc.

Steven R Wallace

4
4

Tacoma Public Utilities
Utility Services, Inc.

Keith Morisette
Brian Evans-Mongeon

4

Wisconsin Energy Corp.

5

AEP Service Corp.

Brock Ondayko

5
5

Amerenue
Arizona Public Service Co.

Sam Dwyer
Scott Takinen

5

Associated Electric Cooperative, Inc.

Matthew Pacobit

5

BC Hydro and Power Authority
Boise-Kuna Irrigation District/dba Lucky
peak power plant project
Bonneville Power Administration

Clement Ma

5
5

Anthony P Jankowski

Negative

SUPPORTS
THIRD PARTY
COMMENTS (Seminole
Electric
Cooperative
comments
submitted by
Maryclaire
Yatsko)

Affirmative
Abstain
Negative

SUPPORTS
THIRD PARTY
COMMENTS (MISO)

Abstain
Affirmative
Abstain

Mike D Kukla
Francis J. Halpin

5

Brazos Electric Power Cooperative, Inc.

Shari Heino

5
5
5

City of Austin dba Austin Energy
City of Redding
City of Tallahassee

Jeanie Doty
Paul A. Cummings
Karen Webb

5

City Water, Light & Power of Springfield

Steve Rose

5

Colorado Springs Utilities

Michael Shultz

5

Consolidated Edison Co. of New York

Wilket (Jack) Ng

5

Consumers Energy Company

David C Greyerbiehl

5

Dairyland Power Coop.

Tommy Drea

5

Dominion Resources, Inc.

Mike Garton

5

Duke Energy

Dale Q Goodwine

5

Electric Power Supply Association

John R Cashin

5

Entergy Services, Inc.

Tracey Stubbs

Non-Binding Poll Results
Project 2010-14.1 BAL-002-2 | October 2014

Affirmative
Abstain

Affirmative
Negative

SUPPORTS
THIRD PARTY
COMMENTS (ACES)

Abstain
Affirmative
Affirmative

Negative

SUPPORTS
THIRD PARTY
COMMENTS NPCC and
NYISO

Abstain
Abstain

Negative

SUPPORTS
THIRD PARTY
COMMENTS (Duke
Energy)

Affirmative

9

5

FirstEnergy Solutions

Kenneth Dresner

Negative

5

Florida Municipal Power Agency

David Schumann

Affirmative

5

Gainesville Regional Utilities

Karen C Alford

5

Great River Energy

Preston L Walsh

5

Imperial Irrigation District

Marcela Y Caballero

5
5

JEA
Kansas City Power & Light Co.

John J Babik
Brett Holland

5

Lakeland Electric

James M Howard

5
5
5

5

Lincoln Electric System
Dennis Florom
Los Angeles Department of Water & Power Kenneth Silver
Manitoba Hydro
S N Fernando
Massachusetts Municipal Wholesale
David Gordon
Electric Company
MEAG Power
Steven Grego

5

MidAmerican Energy Co.

5

Negative

SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF
ACES)

Affirmative
Affirmative
Abstain
Abstain
Affirmative
Abstain
Affirmative

Neil D Hammer

5

Muscatine Power & Water

Mike Avesing

5

Nebraska Public Power District

Don Schmit

Negative

SUPPORTS
THIRD PARTY
COMMENTS (NSRF
comments)

Abstain

5

New York Power Authority

Wayne Sipperly

Negative

5

NextEra Energy

Allen D Schriver

Affirmative

5

Northern Indiana Public Service Co.

William O. Thompson

5

Oglethorpe Power Corporation

Bernard Johnson

5

Oklahoma Gas and Electric Co.

Henry L Staples

5

Omaha Public Power District

Mahmood Z. Safi

5

Orlando Utilities Commission

Richard K Kinas

5
5
5

PacifiCorp
Platte River Power Authority
Portland General Electric Co.

Bonnie Marino-Blair
Roland Thiel
Matt E. Jastram

5

PowerSouth Energy Cooperative

Tim Hattaway

Non-Binding Poll Results
Project 2010-14.1 BAL-002-2 | October 2014

SUPPORTS
THIRD PARTY
COMMENTS (Standards
Review
Committee
(SRC) of the
ISO/RTO
Council via
PJM)

SUPPORTS
THIRD PARTY
COMMENTS (NPCC
comments)

Abstain

Abstain
Affirmative
Affirmative

10

5

PPL Generation LLC

Annette M Bannon

5

PSEG Fossil LLC
Public Utility District No. 2 of Grant
County, Washington
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light

Tim Kucey

5
5
5
5
5
5

Negative

Abstain

Michiko Sell

Affirmative

Lynda Kupfer
Susan Gill-Zobitz
William Alkema
Lewis P Pierce
Michael J. Haynes

Affirmative
Affirmative
Affirmative
Affirmative
Abstain

5

Seminole Electric Cooperative, Inc.

Brenda K. Atkins

Negative

5

Snohomish County PUD No. 1

Sam Nietfeld

Negative

5

South Carolina Electric & Gas Co.

Edward Magic

5
5
5
5

Southern California Edison Company
Southern Company Generation
Tacoma Power
Tampa Electric Co.

Denise Yaffe
William D Shultz
Chris Mattson
RJames Rocha

5

Tenaska, Inc.

Scott M. Helyer

5
5

Tennessee Valley Authority
Tri-State G & T Association, Inc.

David Thompson
Mark Stein

5

U.S. Army Corps of Engineers

Melissa Kurtz

5

U.S. Bureau of Reclamation

Martin Bauer

5

Wisconsin Electric Power Co.

Linda Horn

5

Xcel Energy, Inc.

Liam Noailles

6
6
6

AEP Marketing
Ameren Energy Marketing Co.
APS

Edward P. Cox
Jennifer Richardson
Randy A. Young

6

Associated Electric Cooperative, Inc.

Brian Ackermann

6
6
6
6

Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC

Brenda S. Anderson
Lisa Martin
Marvin Briggs
Robert Hirchak

Non-Binding Poll Results
Project 2010-14.1 BAL-002-2 | October 2014

SUPPORTS
THIRD PARTY
COMMENTS (PPL NERC
Registered
Affiliates)

SUPPORTS
THIRD PARTY
COMMENTS (Posted by
Seminole
Corporate
Compliance)
SUPPORTS
THIRD PARTY
COMMENTS (Seattle City
Light)

Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain

Abstain
Abstain
Affirmative
Negative

SUPPORTS
THIRD PARTY
COMMENTS (AECI)

Affirmative
Abstain
Affirmative
Affirmative

11

6

Colorado Springs Utilities

Shannon Fair

Negative

6

Con Edison Company of New York

David Balban

Negative

6

Duke Energy

Greg Cecil

Negative

6

Entergy Services, Inc.

Terri F Benoit

6

FirstEnergy Solutions

Kevin Querry

6

Florida Municipal Power Agency

Richard L. Montgomery

6

Florida Municipal Power Pool

Thomas Washburn

6

Florida Power & Light Co.

Silvia P Mitchell

6

Great River Energy

Donna Stephenson

6

Imperial Irrigation District

Cathy Bretz

6

Kansas City Power & Light Co.

Jessica L Klinghoffer

6

Lakeland Electric

6
6
6
6

Lincoln Electric System
Eric Ruskamp
Los Angeles Department of Water & Power Brad Packer
Luminant Energy
Brenda Hampton
Manitoba Hydro
Blair Mukanik

6

Modesto Irrigation District

James McFall

6

Muscatine Power & Water

John Stolley

Non-Binding Poll Results
Project 2010-14.1 BAL-002-2 | October 2014

Paul Shipps

Negative

SUPPORTS
THIRD PARTY
COMMENTS ((Northeast
Power
Coordinating
Council)
NPPC)
SUPPORTS
THIRD PARTY
COMMENTS (NPCC)
SUPPORTS
THIRD PARTY
COMMENTS (Duke
Energy)
SUPPORTS
THIRD PARTY
COMMENTS (Standards
Review
Committee
(SRC) of the
ISO/RTO
Council via
PJM)

Affirmative
Affirmative

Negative

SUPPORTS
THIRD PARTY
COMMENTS (MRO and
ACES)

Affirmative

Negative

SUPPORTS
THIRD PARTY
COMMENTS (Duke
Energy)

Abstain
Affirmative
Abstain
Affirmative

Negative

SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)

12

6

New York Power Authority

Saul Rojas

6
6

Northern Indiana Public Service Co.
Omaha Public Power District

Joseph O'Brien
Douglas Collins

6

PacifiCorp

Kelly Cumiskey

6

Platte River Power Authority

Carol Ballantine

6

Portland General Electric Co.

Ty Bettis

6

Power Generation Services, Inc.

Stephen C Knapp

6

Powerex Corp.

Daniel W. O'Hearn

Negative

Abstain
Abstain
Abstain

6

PPL EnergyPlus LLC

Elizabeth Davis

Negative

6
6
6
6

PSEG Energy Resources & Trade LLC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper

Peter Dolan
Diane Enderby
Steven J Hulet
Michael Brown

Abstain
Affirmative
Affirmative
Affirmative

6

Seattle City Light

Dennis Sismaet

Negative

6

Seminole Electric Cooperative, Inc.

Trudy S. Novak

Negative

6

Snohomish County PUD No. 1

Kenn Backholm

Negative

6

Southern California Edison Company
Southern Company Generation and
Energy Marketing

Lujuanna Medina

Affirmative

John J. Ciza

Affirmative

Tacoma Public Utilities

Michael C Hill

6

Tampa Electric Co.

Benjamin F Smith II

6

Tennessee Valley Authority

Marjorie S. Parsons

6

Westar Energy

Grant L Wilkerson

6

Western Area Power Administration - UGP
Peter H Kinney
Marketing

7

EnerVision, Inc.

6
6

Non-Binding Poll Results
Project 2010-14.1 BAL-002-2 | October 2014

SUPPORTS
THIRD PARTY
COMMENTS NPCC RSC
Comments

SUPPORTS
THIRD PARTY
COMMENTS (PPL NERC
Registered
Affiliates)

SUPPORTS
THIRD PARTY
COMMENTS (Paul Haase)
SUPPORTS
THIRD PARTY
COMMENTS (Seminole
Electric
Cooperative's
Corporate
Compliance
department)
SUPPORTS
THIRD PARTY
COMMENTS (Seattle City
Light)

Abstain

Thomas W Siegrist

13

7

Steel Manufacturers Association

James Brew

8

Roger C Zaklukiewicz

8

Robert Blohm

8

Edward C Stein

8

Debra R Warner

Debra R Warner

8

Energy Mark, Inc.

Howard F. Illian

Negative
Affirmative

8

Volkmann Consulting, Inc.

Terry Volkmann

Negative

9

Commonwealth of Massachusetts
Department of Public Utilities

Donald Nelson

Negative

Florida Reliability Coordinating Council
Midwest Reliability Organization

Linda C Campbell
Russel Mountjoy

10
10

SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
SUPPORTS
THIRD PARTY
COMMENTS (NPCC)

Abstain
Affirmative

10

New York State Reliability Council

Alan Adamson

Negative

10

Northeast Power Coordinating Council

Guy V. Zito

Negative

10

ReliabilityFirst Corporation

Anthony E Jablonski

Negative

10

Texas Reliability Entity, Inc.

Donald G Jones

10

Western Electricity Coordinating Council

Steven L. Rueckert

Non-Binding Poll Results
Project 2010-14.1 BAL-002-2 | October 2014

SUPPORTS
THIRD PARTY
COMMENTS (NPCC)

SUPPORTS
THIRD PARTY
COMMENTS (NPCC)
COMMENT
RECEIVED
COMMENT
RECEIVED

Affirmative
Abstain

14































Consideration of
Comments Summary
Project 2010-14.1 BARC – Reserves
BAL-002-2
January 2015

3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com
NERC|ConsiderationofComments–Project2010Ͳ14.1BARCͲReserves|January2015
1of6


Introduction............................................................................................................................... ................................3
ConsiderationofComments............................................................................................................................... .......4
Purpose............................................................................................................................... ...................................4
NERCGlossaryTerms............................................................................................................................... ..............4
ApplicabilitySection............................................................................................................................... ................4
EnergyEmergencyAlertLevel2orLevel3............................................................................................................4
RequirementR1............................................................................................................................... ......................5
RequirementR2............................................................................................................................... ......................5
MeasureM2............................................................................................................................... ............................6
ViolationSeverityLevels(VSLs)............................................................................................................................. 6
BackgroundDocument............................................................................................................................... ...........6
ReliabilityStandardAuditWorksheet(RSAW)......................................................................................................6









NERC|ConsiderationofComments–Project2010Ͳ14.1BARCͲReserves|January2015
2of6

Introduction

Introduction



TheProject2010Ͳ14.1DraftingTeamthanksallcommenterswhosubmittedcommentsontheproposedrevisions
to BALͲ002Ͳ2. The standard was posted for a 45Ͳday formal comment period from August 19, 2014 through
October 3, 2014. Stakeholders were asked to provide feedback on the standard and associated documents
through a special electronic comment form.  There were 28 sets of responses, including comments from
approximately109differentpeoplefromapproximately74companiesrepresentingall10IndustrySegments..

Allcommentssubmittedmaybereviewedintheiroriginalformatontheprojectpage.

Ifyoufeelthatyourcommenthasbeenoverlooked,pleaseletusknowimmediately.Ourgoalistogiveevery
commentseriousconsiderationinthisprocess.Ifyoufeeltherehasbeenanerrororomission,youcancontact
DirectorofStandards,ValerieAgnew,at404Ͳ446Ͳ2566orat[email protected].Inaddition,thereisaNERC
ReliabilityStandardsAppealsProcess.1




1

TheappealsprocessisintheStandardProcessesManual:http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf


NERC|ConsiderationofComments–Project2010Ͳ14.1BARCͲReserves|January2015
3of6



Consideration of Comments
Purpose
TheBARCStandardDraftingTeam(SDT)appreciatesindustry’scommentsontheBALͲ002Ͳ2standard.TheSDT
reviewedallcommentscarefullyandmadechangestothestandardaccordingly;however,thenewStandards
ProcessManual(SPM)doesnotrequiretheSDTtorespondtoeachcommentifanadditionalcommentperiod
andballotareneeded.ThefollowingpagesareasummaryofthecommentsreceivedandhowtheSDTaddressed
them.Ifaspecificcommentwasnotaddressedinthesummaryofcomments,pleasecontacttheNERCstandards
developertodiscuss.

NERC Glossary Terms
OnecommenterfeltthattheproposeddefinitionsshouldnotbeaddedtotheNERCGlossaryofTermsandonly
bereflectedinthestandard.TheSDTbelievesthatbyaddingthesetermstotheglossaryitwillprovideconsistency
intheiruseandeliminateanymisunderstandingsthatcouldariseinthefuture.

BasedonIndustrycommentsreceivedtheSDTremovedtheword“Interconnection”fromthephrase“Lossof
generatorInterconnectionFacility”fromthedefinitionofBalancingContingencyEvent.

AcoupleofIndustrycommenterswantedtoaddtheterm“curtailmentofenergytransactions”tothedefinition
ofBalancingContingencyEvent.TheSDTdisagreessincethisiscoveredinthesubͲpartsofRequirementR2.

One commenter wanted to remove item “B” from the definition of Balancing Contingency Event.  The SDT
discussedtheircommentbutdecidedtoleaveitinthedefinitionasitprovidesadditionalclarity.

OnecommenterfeltthatthesubͲpartsaandbofPartAoftheBalancingContingencyEventdefinitionshouldbe
eliminatedandsimplystate“Anysuddenlossofgenerationthatcausesanunexpectedchangetotheresponsible
entity’sACE”.TheSDTdisagreeswithsimplifyingthedefinitioninthismanner.TheSDTbelievesthatthedetail
isnecessarytominimizeinterpretationsofthetruemeaning.

A couple of commenters felt that the reporting thresholds in the Reportable Balancing Contingency Event
definitionweretoohighwhileacoupleofothercommentersfeltthattheyweretoolow.TheSDTrevisedthebox
plotsusedtosetthethresholdstoonlyuselossofaresource.TherevisedboxplotsreinforcetheSDT’schoiceof
thereportingthresholdsforeachInterconnection.


Applicability Section

One commenter felt that the term Responsible Entity should not be capitalized since it was not in the NERC
GlossaryofTerms.TheSDTdisagreessincethetermisdefinedintheApplicabilitySectionofthestandard.

AcoupleofcommentersquestionedwhattheSDTmeantbyuseoftheterm“activestatus”.TheSDTbelieves
thatthistermprovidessufficientclarityandthatthoseBA’sandRSG’sthatallowforaBAtoeitherusetheRSGto
recoverfromaneventorrecoverfromtheeventontheirownunderstandtheuseoftheterm.



Energy Emergency Alert Level 2 or Level 3

Based on Industry comments received the SDT added Attachment 3 to the Background Document to provide
additionalinformationregardingtheinteractionbetweenBALͲ002Ͳ2andEnergyEmergencyAlerts.


NERC|ConsiderationofComments–Project2010Ͳ14.1BARCͲReserves|January2015
4of6

Requirement R1

ConsiderationofComments


BasedoncommentsreceivedfromtheindustrytheSDTaddedthephrase“ReliabilityCoordinatorapproved”to
RequirementR1Part1.2toprovideclaritythattheReliabilityCoordinatorwastheentitythatdeterminedwhen
anEnergyEmergencyAlertcouldbeestablishedandnottheBalancingAuthorityortheReserveSharingGroup.

AcoupleofIndustrycommenterssuggestedmodifyingRequirementR1Part1.1toallowforusinganalternate
type of calculation rather than CR Form 1.  The SDT is trying to provide a consistent method for calculating
compliancethatcanbeusedgloballyandthereforedecidedtoleavethelanguageasitispresentlywritten.

Afewcommentersstilldidnotagreewithmodifyingthepresentstandard.TheSDTisattemptingtoresolveissues
thathavecomeupwithregardstorespondingtoeventsgreaterthanMSSC.Thisneedisdemonstratedbythe
requestforinterpretationthatwasrequestedbytheNWPPandhasbeenfiledwithFERC.

Onecommentersuggestedaddingthephrase‘beginningatthetimeof”toRequirementR1Part1.3.TheSDT
disagreeswiththeirsuggestion.TheSDTbelievesthatthepresentwordingprovidesthenecessaryclarityforan
entitytounderstandandbecompliantwiththispartoftherequirement.

OnecommentersuggestedthattheSDTchangetheContingencyEventRecoveryPeriodfrom15minutesto30
minutes.TheSDTdiscussedthiscommentbutdecidedthatsincetheydidnothaveanyempiricalevidenceto
supportsuchachangetherecoveryperiodshouldremainatthe15minutelevel.

OnecommenterquestionedwhenitwouldbenecessaryforanentitytouseCRForm1.Theformistobeused
foreveryreportableevent.TheSDTremovedany“filing”requirementsfromthestandardastheybelievethat
thisisanadministrativeactivityandshouldnotbeincludedinanyreliabilitystandard(Paragraph81).

OnecommenterwantedRequirementR1Part1.2and1.3tobecombined.TheSDTdiscussedthisatlengthand
decidedtoleavethemastheyarepresentlywrittensincetheybelievethatitprovidesnecessaryclarity.



Requirement R2

BasedoncommentsreceivedfromtheindustrytheSDTaddedlanguagetoRequirementR2toprovideadditional
clarity.Specifically,theSDTaddedlanguagedescribingperiodswhenanEntitywouldnotbeheldtocompliance
withRequirementR2andtheassociatedrecoveryperiod.

Several commenters did not believe that Requirement R2 was necessary and actually created a “commodity
obligation”.TheSDTdisagreesandbelievestherequirementisnecessaryforreliabilityandtomeettheapproach
for the FERC directive.  The current standard (Requirement R3 part 3.1) requires a BA or RSG to maintain
ContingencyReserveatleastequaltoitsMSSC.

SomecommentersfeltthatthisstandardrequiredanentitytocarryreservesinexcessofMSSC.TheSDTdisagrees
andfeelsthatthelanguageclearlystatesthatanentitywouldonlybeheldtocomplianceforeventsuptoMSSC.

OnecommentersuggestedthatthelanguageinRequirementR2neededtobemodifiedtoremovethe“clock
hour”.The SDTdisagrees.TheSDTbelievesthatremovingthe“clockhour”language wouldaddanorderof
complexitytotherequirementandincreasethedataretentionrequirements.Also,theSDTusedtheterm“clock
hour”toallowforthenormalfluctuationsthatoccur.

OneentityfeltthatthestandardwasfocusingmoreontrackingContingencyReserveratherthanhowContingency
Reservecouldbeused.TheSDTdisagreeswiththeirconcernbuttheSDTdidmodifytherequirementtoprovide
NERC|ConsiderationofComments–Project2010Ͳ14.1BARCͲReserves|January2015
5of6

ConsiderationofComments


additionalclarityonhowContingencyReservecouldbeused.TheSDTalsobelievesthatbyallowingfortheuse
ofContingencyReserveforothereventsthenanentitywouldhavetobeabletotrackitsContingencyReserve.

Onecommenterquestionedwhatscanrateshouldbeused.TheminimumscanrateisdefinedinBALͲ005Ͳ0.2b.

OnecommenteraskedthequestioniftheSDTthoughtthatMSSCcouldchangeduringthehourandwhetherthey
meantfortheMSSCaveragingtobedoneinthesamemannerasContingencyReserve.TheSDTbelievesthatthe
MSSCcouldchangedependingontheconditionstheentityisincurring.TheSDTisrequiringthattheaveraging
bedoneinthesamemannerthatContingencyReserveiscalculated.

One entity felt that Requirement R2 could allow for gaming in that a BA could d3eclare an EEA simply to be
compliantwithBALͲ002Ͳ2.TheSDTdisagreeswiththecomment.TheSDTnotesthattheBAdoesnotdeclarethe
EEAbuttheyapproachtheRCtorequestthatanEEAgointoeffect.TheRChasthefinalsayastowhetherornot
anEEAwouldbedeclared.



Measure M2

TheSDTmodifiedthelanguageinMeasureM2toprovideadditionalclarityastohowanentitycoulddemonstrate
compliance.

Onecommenterstatedthattheywerenotsureastohowtodemonstratecompliance.TheSDTdiscussedtheir
concernanddecidedtomodifythemeasuretoprovideadditionalclarityastohowtodemonstratecompliance.



Violation Severity Levels (VSLs)

TheSDTmodifiedtheVSLforRequirementR1toprovideadditionalclarity.

OnecommenterfeltthattheVSLforRequirementR1shouldhavesomethingtoaccountforanentitynotusing
CRForm1.TheSDTagreedandmodifiedthelowerVSLforRequirementR1toaccountfornotusingCRForm1.




Background Document

BasedonindustrycommentstheSDTmodifiedtheBALͲ002Ͳ2BackgroundDocumenttoprovideadditionalclarity
andexamplesofcalculations.

Acoupleofcommentersquestionedthedevelopmentofthereportingthresholdssincetheyappearedtouseboth
lossofaresourceandlossofload.TheSDTagreedandmodifiedtheboxplotstoonlyincludelossofaresource.

OnecommentersuggestedremovingthetermEnergyDeficientEntityfromtheBackgroundDocumentsinceitis
notusedinthenewEOPͲ011Ͳ1standard.TheSDTdiscussedthiscommentbutdecidedtokeepthelanguageas
itispresentlywrittensincethetermisusedinthepresentEOPͲ002Ͳ3.1standardandthereisnoguaranteethat
theproposedstandardEOPͲ011Ͳ1willbeapprovedbyFERC.


Reliability Standard Audit Worksheet (RSAW)

ThecurrentrevisedReliabilityStandardsAuditWorksheet(RSAW)willberevisedtoreflectallmodificationsmade
tothepresentstandard.


NERC|ConsiderationofComments–Project2010Ͳ14.1BARCͲReserves|January2015
6of6

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

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
(Describe the type of action associated with this posting, such as 30-day informal comment
period, 45-day formal comment period with parallel ballot, 45-day formal comment period with
parallel additional ballot, final ballot.)

Completed Actions

Date

The SAR for Project 2007-18, Reliability Based Controls, was posted
for a 30-day formal comment period.

May 15, 2007

A revised SAR for Project 2007-05, Reliability Based Controls, was
posted for a second 30-day formal comment period.

September 10, 2007

The Standards Committee approved Project 2007-18, Reliability
Based Controls, to be moved to standard drafting.

December 11, 2007

The SAR for Project 2007-05, Balancing Authority Controls, was
posted for a 30-day formal comment period.

July 3, 2007

The Standards Committee approved Project 2007-05, Balancing
Authority Controls, to be moved to standard drafting.

January 18, 2008

The Standards Committee approved the merger of Project 2007-05,
Balancing Authority Controls, and Project 2007-18, Reliability-based
Control, as Project 2010-14, Balancing Authority Reliability-based
Controls.

July 28, 2010

The NERC Standards Committee approved breaking Project 2010-14,
Balancing Authority Reliability-based Controls, into two phases and
moving Phase 1 (Project 2010-14.1, Balancing Authority Reliabilitybased Controls – Reserves) into formal standards development.

July 13, 2011

The draft standard was posted for 30-day formal industry comment
period.

June 4, 2012

The draft standard was posted for 45-day formal industry comment
period and initial ballot.

March 12, 2013

The third draft standard was posted for 45-day formal industry
comment period and additional ballot.

August 2, 2013

Posting 6 of Standard: January, 2015

Page 1 of 15

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

The fourth draft standard was posted for 45-day formal industry
comment period and additional ballot.

October 28, 2013

The fifth draft standard was posted for a 45 day formal industry
comment period and additional ballot.

August 20, 2014

Anticipated Actions

Date

45-day formal comment period with parallel additional ballot

February/March
2015

Final ballot

April 2015

NERC Board adoption

May 2015

Posting 6 of Standard: January, 2015

Page 2 of 15

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

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:
Balancing Contingency Event: Any single event described in Subsections (A), (B), or (C) below,
or any series of such otherwise single events, with each separated from the next by less than
one minute.
A. Sudden loss of generation:
a. Due to
i. Unit tripping,
ii. Loss of generator Facility resulting in isolation of the generator from the
Bulk Electric System or from the responsible entity’s electric system, or
iii. Sudden unplanned outage of transmission Facility;
b. And, that causes an unexpected change to the responsible entity’s ACE;
B. Sudden loss of an import, due to forced outage of transmission equipment that causes
an unexpected imbalance between generation and load on the Interconnection.
C. Sudden restoration of a load that was used as a resource that causes an unexpected
change to the responsible entity’s ACE.
Most Severe Single Contingency (MSSC): The Balancing Contingency Event, due to a single
contingency, that would result in the greatest loss (measured in MW) of resource output used
by the Reserve Sharing Group (RSG) or a Balancing Authority that is not participating as a
member of a RSG at the time of the event to meet firm system load and export obligation
(excluding export obligation for which Contingency Reserve obligations are being met by the
Sink Balancing Authority).
Reportable Balancing Contingency Event: Any Balancing Contingency Event resulting in a loss
of MW output less than or equal to the Most Severe Single Contingency, and greater than or
equal to the lesser amount of: (i) 80% of the Most Severe Single Contingency, or (ii) the amount
listed below for the applicable Interconnection, and occurring within a one-minute interval of
the initial sudden decline in ACE based on EMS scan rate data. Prior to any given calendar
quarter, the 80% threshold may be reduced by the responsible entity upon written notification
to the Regional Entity.
x

Eastern Interconnection - 900 MW

x

Western Interconnection – 500 MW

x

ERCOT – 800 MW

Posting 6 of Standard: January, 2015

Page 3 of 15

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

x

Quebec – 500 MW

Contingency Event Recovery Period: A period beginning at the time that the resource output
begins to decline within the first one-minute interval that defines a Balancing Contingency
Event, and extends for fifteen minutes thereafter.
Contingency Reserve Restoration Period: A period not exceeding 90 minutes following the end
of the Contingency Event Recovery Period.
Pre-Reporting Contingency Event ACE Value: The average value of Reporting ACE, or Reserve
Sharing Group Reporting ACE when applicable, in the 16-second interval immediately prior to
the start of the Contingency Event Recovery Period based on EMS scan rate data.
Reserve Sharing Group Reporting ACE: At any given time of measurement for the applicable
Reserve Sharing Group, the algebraic sum of the ACEs (or equivalent as calculated at such time
of measurement) of the Balancing Authorities participating in the Reserve Sharing Group at the
time of measurement.
Contingency Reserve: The provision of capacity that may be deployed by the Balancing
Authority to respond to a Balancing Contingency Event and other contingency requirements
(such as Energy Emergency Alerts as specified in the associated EOP standard). The capacity
may be provided by resources such as Demand-Side Management (DSM), Interruptible Load
and unloaded generation.

Posting 6 of Standard: January, 2015

Page 4 of 15

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

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: Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event

2.
3.

Number: BAL-002-2
Purpose: To ensure the Balancing Authority or Reserve Sharing Group balances
resources and demand and returns the Balancing Authority's or Reserve Sharing
Group's Area Control Error to defined values (subject to applicable limits) following a
Reportable Balancing Contingency Event.

4.

Applicability:
4.1. Responsible Entity
4.1.1. Balancing Authority
4.1.1.1.
A Balancing Authority that is a member of a Reserve
Sharing Group is the Responsible Entity only in periods during
which the Balancing Authority is not in active status under the
applicable agreement or governing rules for the Reserve Sharing
Group.
4.1.2. Reserve Sharing Group

5.

Effective Date: The standard shall become effective on the first day of the first
calendar quarter that is six months after the date that the standard is approved by an
applicable governmental authority or as otherwise provided for in a jurisdiction where
approval by an applicable governmental authority is required for a standard to go into
effect. Where approval by an applicable governmental authority is not required, the
standard shall become effective on the first day of the first calendar quarter that is six
months after the date the standard is adopted by the NERC Board of Trustees or as
otherwise provided for in that jurisdiction.

6.

Background:
Reliably balancing an Interconnection requires frequency management and all of its
aspects. Inputs to frequency management include Tie-Line Bias Control, Area Control
Error (ACE), and the various Requirements in NERC Resource and Demand Balancing
Standards, specifically BAL-001-2 Real Power Balancing Control Performance and BAL003-1 Frequency Response and Frequency Bias Setting.

B. Requirements and Measures

Posting 6 of Standard: January, 2015

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BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

Rationale for Requirement R1: Requirement R1 reflects the operating principles first
established by NERC Policy 1. Its objective is to assure the Responsible Entity balances
resources and demand and returns its Reportable Area Control Error (ACE) to defined
values (subject to applicable limits) following a Reportable Balancing Contingency Event.
It requires the Responsible Entity to recover from events that would be less than or equal
to the Responsible Entity’s MSSC. It establishes the amount of Contingency Reserve and
recovery and restoration timeframes the Responsible Entity must demonstrate in a
compliance evaluation. It is intended to eliminate the ambiguities and questions
associated with the existing standard. In addition, it allows Responsible Entities to have a
clear way to demonstrate compliance and support the Interconnection to the full extent
of its MSSC.
Requirement R1 does not apply when an entity experiences a Balancing Contingency
Event that exceeds its MSSC (which includes multiple Balancing Contingency Events as
described in R1.3 below) because a fundamental goal of the SDT is to assure the
Responsible Entity has enough flexibility to maintain service to load while managing
reliability. Also, the SDT’s intent is to eliminate any potential overlap or conflict with any
other NERC Reliability Standard to eliminate duplicative reporting, and other issues.
R1.

The Responsible Entity experiencing a Reportable Balancing Contingency Event shall,
within the Contingency Event Recovery Period, demonstrate recovery by returning its
Reporting ACE to at least the recovery value of: [Violation Risk Factor: Medium] [Time
Horizon: Real-time Operations]
x

Zero, (if its Pre-Reporting Contingency Event ACE Value was positive or equal
to zero); however, during the Contingency Event Recovery Period, any
Balancing Contingency Event that occurs shall reduce the required recovery: (i)
beginning at the time of, and (ii) by the magnitude of, each individual
Balancing Contingency Event,

or,
x

Its Pre-Reporting Contingency Event ACE Value, (if its Pre-Reporting
Contingency Event ACE Value was negative); however, during the Contingency
Event Recovery Period, any Balancing Contingency Event that occurs shall
reduce the required recovery: (i) beginning at the time of, and (ii) by the
magnitude of, each individual Balancing Contingency Event.

1.1. All Reportable Balancing Contingency Events will be documented using CR Form
1.
1.2. A Responsible Entity is not subject to compliance with Requirement R1 when it
is experiencing a Reliability Coordinator approved Energy Emergency Alert Level
under which Contingency Reserves have been activated.
1.3. Requirement R1 (in its entirety) does not apply:

Posting 6 of Standard: January, 2015

Page 6 of 15

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

x

(i) when the Responsible Entity experiences a Balancing Contingency
Event that exceeds its Most Severe Single Contingency, or

x

(ii) after multiple Balancing Contingency Events for which the combined
magnitude exceeds the Responsible Entity's Most Severe Single
Contingency for those events that occur within a 105-minute period.

M1. Each Responsible Entity shall have, and provide upon request, as evidence, a CR Form
1 with date and time of occurrence to show compliance with Requirement R1, or
dated documentation that demonstrates compliance with Requirement 1.2 and 1.3.
Rationale for Requirement R2: R2 establishes a uniform continent-wide contingency
reserve requirement. R2 establishes a requirement that contingency reserve be at least
equal to the applicable entity’s Most Severe Single Contingency. By including a definition
of Most Severe Single Contingency and R2, a consistent uniform continent-wide
contingency reserve requirement has been established. Its goal is to assure that the
Responsible Entity will have sufficient contingency reserve that can be deployed to meet
R1.
FERC Order 693 (at P356) directed BAL-002 to be developed as a continent-wide
contingency reserve policy. R2 fulfills the requirement associated with the required
amount of contingency reserve a Responsible Entity must have available to respond to a
Reportable Balancing Contingency Event. Within FERC Order 693 (at P336) the
Commission noted that the appropriate mix of operating reserve, spinning reserve and
non-spinning reserve should be addressed. However, the Order predated the approval of
the new BAL-003, which addresses frequency responsive reserve and the amount of
frequency response obligation. With the development of BAL-003, and the associated
reliability performance requirement, the SDT believes that, with R2 of BAL-002 and the
approval of BAL-003, the Commission’s goals of a continent-wide contingency reserves
policy is met. The suites of BAL standards (BAL-001, BAL-002, and BAL-003) are all
performance-based. With the suite of standards and the specific requirements within
each respective standard, a continent-wide contingency policy is established.
In the Violation Severity Levels for Requirement R1, the impact of the Responsible Entity
recovering from a Reportable Balancing Contingency Event depends on the amount of its
Contingency Reserve available and whether it has sufficient response. Additionally, the
drafting team understands that the Responsible Entity’s available Contingency Reserve
may vary slightly from MSSC at any time. This variability is recognized in Requirement R2
through averaging the available Contingency Reserve over each Clock Hour.
The ideal goal of maintaining an amount of Contingency Reserve to cover the Most
Severe Single Contingency at all times is not necessarily in the best interest of reliability.
It may have the unintended result of tying operators' hands by removing use of their

Posting 6 of Standard: January, 2015

Page 7 of 15

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

available contingency reserve from their toolbox in order to maintain service to load or
manage other reliability issues. By allowing for the occasional use of this minimal amount
of Contingency Reserve at the operators' discretion for other contingencies, reliability is
enhanced. The SDT crafted the proposed standard to encourage the operators to use, at
their discretion and within the limits set forth in the standard, their available contingency
reserve to best serve reliability in Real-time. The last thing that anyone desires is to have
Contingency Reserve held available and the lights go off because the standard would
penalize the operator for using the Contingency Reserve to maintain service to the load.
However, the drafting team did not believe that the use of reserves for issues other than
a Reportable Balancing Contingency Event should be unbounded. The SDT limited the use
of Contingency Reserve.
R2. The Responsible Entity shall maintain Contingency Reserve, averaged over each Clock
Hour, greater than or equal to its average Clock Hour Most Severe Single Contingency,
except during one or more of the following periods when the Responsible Entity is:
[Violation Risk Factor: Medium] [Time Horizon: Real-time Operations]
2.1 using its Contingency Reserve, for a period not to exceed 90 minutes,
to mitigate the reliability concerns associated with Contingencies that
are not Balancing Contingency Events; and/or
2.2 using its Contingency Reserve, for a period not to exceed 90 minutes,
to respond to an Operating Instruction requiring the use of
Contingency Reserve; and/or
2.3 using its Contingency Reserve for a period not to exceed 90 minutes,
to resolve the exceedance of a System Operating Limit (SOL) or
Interconnection Reliability Operation Limit (IROL) that requires the
use of Contingency Reserve; and/or
2.4 in a Contingency Reserve Restoration Period; and/or
2.5 in a Contingency Event Recovery Period; and/or
2.6 in an Energy Emergency Alert Level under which the Responsible
Entity no longer has required Contingency Reserve available provided
that the Responsible Entity has made preparations for interruption of
Firm Load to replace the shortfall of Contingency Reserve to avoid the
uncontrolled failure of components or cascading outages of the
Interconnection. For this exemption to apply, the preparations must
be initiated within 5 minutes from the time that the Energy
Emergency Alert Level is declared.
M2. Each Responsible Entity shall have dated documentation that demonstrates
compliance with Requirement R2. Evidence of compliance may include, but is not
limited to, documenting Contingencies and Energy Emergency Alert Levels through
outage records, operator logs, and others.

Posting 6 of Standard: January, 2015

Page 8 of 15

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

Compliance may be achieved by demonstrating that:
x

Contingency Reserve, averaged over each Clock Hour, meets or exceeds the
required Contingency Reserve; or,

x

Contingency Reserve has been restored to the required Contingency Reserve
levels within the specified period: or,

x

the sum of the Contingency Reserve and Firm Load available as a substitute for
unavailable Contingency Reserve reaches the required Contingency Reserve
level within the specified period;
Any shortfall from compliance will be measured as compliance of 100% minus
the shortfall’s percentage share of MSSC.

If the recording of Contingency Reserve or MSSC is interrupted such that more than
50 percent of the samples within the clock hour are invalid data, then that clock hour
is excluded from evaluation. If any portion of the Clock Hour is excluded by rule in
Requirement R2, then compliance with that portion of the hour not excluded may be
shown by either determination of the integrated value for that portion of the hour
not excluded by the rule or an instantaneous value showing reserves any time during
the excluded period.
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 Responsible Entity shall retain data or evidence to show compliance for
the current year, plus three previous calendar years, unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer
period of time as part of an investigation.
If a Responsible Entity is found noncompliant, it shall keep information related
to the noncompliance until found compliant, or for the time period specified
above, whichever is longer.

Posting 6 of Standard: January, 2015

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BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

The Compliance Enforcement Authority shall keep the last audit records and
all subsequent requested and submitted records.
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
The Responsible Entity may use Contingency Reserve for any Balancing
Contingency Event and as required for any other applicable standards.

Posting 6 of Standard: January, 2015

Page 10 of 15

Real-time
Operations

Real-time
Operations

R1.

R2.

Lower VSL

Medium The Responsible Entity
had Contingency
Reserve but the Clock
Hour average amount
of Contingency
Reserve was less than
100% of MSSC but was
greater than or equal

The Responsible Entity
failed to use CR Form 1
to document a
Reportable Balancing
Contingency Event.

OR

Medium The Responsible Entity
recovered less than
100% but more than
90% of required
recovery from a
Reportable Balancing
Contingency Event
during the
Contingency Event
Recovery Period

VRF

Draft # of Standard: Date Submitted for Posting

Time
Horizon

R#

Table of Compliance Elements

The Responsible Entity
had Contingency
Reserve but the Clock
Hour average amount
of Contingency
Reserve was less than
80% of MSSC but was
greater than or equal

The Responsible Entity
recovered 80% or less
but more than 70% of
required recovery
from a Reportable
Balancing Contingency
Event during the
Contingency Event
Recovery Period.

The Responsible Entity
recovered 90% or less
but more than 80% of
required recovery
from a Reportable
Balancing Contingency
Event during the
Contingency Event
Recovery Period.

The Responsible Entity
had Contingency
Reserve but the Clock
Hour average amount
of Contingency
Reserve was less than
90% of MSSC but was
greater than or equal

High VSL

Moderate VSL

Violation Severity Levels

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event

Page 11 of 15

The Responsible Entity
did not have
Contingency Reserve
that was equal to or
greater than 70% of
MSSC averaged over
the Clock Hour.

The Responsible Entity
recovered 70% or less
of required recovery
during the
Contingency Event
Recovery Period.

Severe VSL

to 80% of MSSC as
averaged over the
Clock Hour.

to 70% of MSSC as
averaged over the
Clock Hour.

August 8, 2005

February 14,
2006

0

0

Action

NERC BOT Adoption

Revised graph on page 3, “10 min.” to “Recovery
time.” Removed fourth bullet.

Removed “Proposed” from Effective Date

Effective Date

Draft # of Standard: Date Submitted for Posting

2

April 1, 2005

Date

0

Version

Version History

CR Form 1

Complete revision

Errata

Errata

New

Change Tracking

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event Background Document

F. Associated Documents

None.

E. Interpretations

None.

D. Regional Variances

to 90% of MSSC as
averaged over the
Clock Hour.

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event

Page 12 of 15

Draft # of Standard: Date Submitted for Posting

R10.

Page 13 of 15

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.
R9.

R8.

R7.

R6.

R5.

R4.

R3.

R2.

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event

Supplemental Material
[Application Guidelines, Guidelines and Technical Basis, Training Material,
Reference Material and/or other Supplemental Material]
R11.

Draft # of Standard: Date Submitted for Posting

Page 14 of 15

Supplemental Material
Rationale
R12. Upon Board approval, the text from the rationale boxes will be moved to this section.
R13.

Draft # of Standard: Date Submitted for Posting

Page 15 of 15

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

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
(Describe the type of action associated with this posting, such as 30-day informal comment
period, 45-day formal comment period with parallel ballot, 45-day formal comment period with
parallel additional ballot, final ballot.)

Completed Actions

Date

The SAR for Project 2007-18, Reliability Based Controls, was posted
for a 30-day formal comment period.

May 15, 2007

A revised SAR for Project 2007-05, Reliability Based Controls, was
posted for a second 30-day formal comment period.

September 10, 2007

The Standards Committee approved Project 2007-18, Reliability
Based Controls, to be moved to standard drafting.

December 11, 2007

The SAR for Project 2007-05, Balancing Authority Controls, was
posted for a 30-day formal comment period.

July 3, 2007

The Standards Committee approved Project 2007-05, Balancing
Authority Controls, to be moved to standard drafting.

January 18, 2008

The Standards Committee approved the merger of Project 2007-05,
Balancing Authority Controls, and Project 2007-18, Reliability-based
Control, as Project 2010-14, Balancing Authority Reliability-based
Controls.

July 28, 2010

The NERC Standards Committee approved breaking Project 2010-14,
Balancing Authority Reliability-based Controls, into two phases and
moving Phase 1 (Project 2010-14.1, Balancing Authority Reliabilitybased Controls – Reserves) into formal standards development.

July 13, 2011

The draft standard was posted for 30-day formal industry comment
period.

June 4, 2012

The draft standard was posted for 45-day formal industry comment
period and initial ballot.

March 12, 2013

The third draft standard was posted for 45-day formal industry
comment period and additional ballot.

August 2, 2013

Posting 6 of Standard: January, 2015

Page 1 of 15

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

The fourth draft standard was posted for 45-day formal industry
comment period and additional ballot.

October 28, 2013

The fifth draft standard was posted for a 45 day formal industry
comment period and additional ballot.

August 20, 2014

Anticipated Actions

Date

45-day formal comment period with parallel additional ballot

February/March
2015

Final ballot

April 2015

NERC Board adoption

May 2015

Posting 6 of Standard: January, 2015

Page 2 of 15

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

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:
Balancing Contingency Event: Any single event described in Subsections (A), (B), or (C) below,
or any series of such otherwise single events, with each separated from the next by less than
one minute.
A. Sudden loss of generation:
a. Due to
i. Unit tripping,
ii. Loss of generator Interconnection Facility resulting in isolation of the
generator from the Bulk Electric System or from the responsible entity’s
electric system, or
iii. Sudden unplanned outage of transmission Facility;
b. And, that causes an unexpected change to the responsible entity’s ACE;
B. Sudden loss of an import, due to forced outage of transmission equipment that causes
an unexpected imbalance between generation and load on the Interconnection.
C. Sudden restoration of a load that was used as a resource that causes an unexpected
change to the responsible entity’s ACE.
Most Severe Single Contingency (MSSC): The Balancing Contingency Event, due to a single
contingency, that would result in the greatest loss (measured in MW) of resource output used
by the Reserve Sharing Group (RSG) or a Balancing Authority that is not participating as a
member of a RSG at the time of the event to meet firm system load and export obligation
(excluding export obligation for which Contingency Reserve obligations are being met by the
Ssink Balancing Authority).
Reportable Balancing Contingency Event: Any Balancing Contingency Event resulting in a loss
of MW output less than or equal to the Most Severe Single Contingency, and greater than or
equal to the lesser amount of: (i) 80% of the Most Severe Single Contingency, or (ii) the amount
listed below for the applicable Interconnection, and occurring within a one-minute interval of
the initial sudden decline in ACE based on EMS scan rate data. Prior to any given calendar
quarter, the 80% threshold may be reduced by the responsible entity upon written notification
to the Regional Entity.
x

Eastern Interconnection - 900 MW

x

Western Interconnection – 500 MW

Posting 6 of Standard: January, 2015

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BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

x

ERCOT – 800 MW

x

Quebec – 500 MW

Contingency Event Recovery Period: A period beginning at the time that the resource output
begins to decline within the first one-minute interval that defines a Balancing Contingency
Event, and extends for fifteen minutes thereafter.
Contingency Reserve Restoration Period: A period not exceeding 90 minutes following the end
of the Contingency Event Recovery Period.
Pre-Reporting Contingency Event ACE Value: The average value of Reporting ACE, or Reserve
Sharing Group Reporting ACE when applicable, in the 16- second interval immediately prior to
the start of the Contingency Event Recovery Period based on EMS scan rate data.
Reserve Sharing Group Reporting ACE: At any given time of measurement for the applicable
Reserve Sharing Group, the algebraic sum of the ACEs (or equivalent as calculated at such time
of measurement) of the Balancing Authorities participating in the Reserve Sharing Group at the
time of measurement.
Contingency Reserve: The provision of capacity that may be deployed by the Balancing
Authority to respond to a Balancing Contingency Event and other contingency requirements
(such as Energy Emergency Alerts as specified in the associated EOP standard). The capacity
may be provided by resources such as Demand- Side Management (DSM), Interruptible Load
and unloaded generation.

Posting 6 of Standard: January, 2015

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BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

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: Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event

2.
3.

Number: BAL-002-2
Purpose: To ensure the Balancing Authority or Reserve Sharing Group balances
resources and demand and returns the Balancing Authority's or Reserve Sharing
Group's Area Control Error to defined values (subject to applicable limits) following a
Reportable Balancing Contingency Event.

4.

Applicability:
4.1. Responsible Entity
4.1.1. Balancing Authority
4.1.1.1.
A Balancing Authority that is a member of a Reserve
Sharing Group is the Responsible Entity only in periods during
which the Balancing Authority is not in active status under the
applicable agreement or governing rules for the Reserve Sharing
Group.
4.1.2. Reserve Sharing Group

5.

Effective Date: The standard shall become effective on the first day of the first
calendar quarter that is six months after the date that the standard is approved by an
applicable governmental authority or as otherwise provided for in a jurisdiction where
approval by an applicable governmental authority is required for a standard to go into
effect. Where approval by an applicable governmental authority is not required, the
standard shall become effective on the first day of the first calendar quarter that is six
months after the date the standard is adopted by the NERC Board of Trustees or as
otherwise provided for in that jurisdiction.

6.

Background:
Reliably balancing an Interconnection requires frequency management and all of its
aspects. Inputs to frequency management include Tie-Line Bias Control, Area Control
Error (ACE), and the various Requirements in NERC Resource and Demand Balancing
Standards, specifically BAL-001-2 Real Power Balancing Control Performance and BAL003-1 Frequency Response and Frequency Bias Setting.

B. Requirements and Measures

Posting 6 of Standard: January, 2015

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BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

Rationale for Requirement R1: Requirement R1 reflects the operating principles first
established by NERC Policy 1. Its objective is to assure the Responsible Entity balances
resources and demand and returns its Reportable Area Control Error (ACE) to defined
values (subject to applicable limits) following a Reportable Balancing Contingency Event.
It requires the Responsible Entity to recover from events that would be less than or equal
to the Responsible Entity’s MSSC. It establishes the amount of Contingency Reserve and
recovery and restoration timeframes the Responsible Entity must demonstrate in a
compliance evaluation. It is intended to eliminate the ambiguities and questions
associated with the existing standard. In addition, it allows Responsible Entities to have a
clear way to demonstrate compliance and support the Interconnection to the full extent
of its MSSC.
Requirement R1 does not apply when an entity experiences a Balancing Contingency
Event that exceeds its MSSC (which includes multiple Balancing Contingency Events as
described in R1.3 below) because a fundamental goal of the SDT is to assure the
Responsible Entity has enough flexibility to maintain service to load while managing
reliability. Also, the SDT’s intent is to eliminate any potential overlap or conflict with any
other NERC Reliability Standard to eliminate duplicative reporting, and other issues.
R1.

The Responsible Entity experiencing a Reportable Balancing Contingency Event shall,
within the Contingency Event Recovery Period, demonstrate recovery by returning its
Reporting ACE to at least the recovery value of: [Violation Risk Factor: Medium] [Time
Horizon: Real-time Operations]
x

Zero, (if its Pre-Reporting Contingency Event ACE Value was positive or equal
to zero); however, during the Contingency Event Recovery Period, any
Balancing Contingency Event that occurs shall reduce the required recovery: (i)
beginning at the time of, and (ii) by the magnitude of, each individual
Balancing Contingency Event,

or,
x

Its Pre-Reporting Contingency Event ACE Value, (if its Pre-Reporting
Contingency Event ACE Value was negative); however, during the Contingency
Event Recovery Period, any Balancing Contingency Event that occurs shall
reduce the required recovery: (i) beginning at the time of, and (ii) by the
magnitude of, each individual Balancing Contingency Event.

1.1. All Reportable Balancing Contingency Events will be documented using CR Form
1.
1.2. A Responsible Entity is not subject to compliance with Requirement R1 when it
is experiencing an Reliability Coordinator approved Energy Emergency Alert
Level under which Contingency Reserves have been activated.
1.3. Requirement R1 (in its entirety) does not apply:

Posting 6 of Standard: January, 2015

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BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

x

(i) when the Responsible Entity experiences a Balancing Contingency
Event that exceeds its Most Severe Single Contingency, or

x

(ii) after multiple Balancing Contingency Events for which the combined
magnitude exceeds the Responsible Entity's Most Severe Single
Contingency for those events that occur within a 105- minute period.

M1. Each Responsible Entity shall have, and provide upon request, as evidence, a CR Form
1 with date and time of occurrence to show compliance with Requirement R1, or
dated documentation that demonstrates compliance with Requirement 1.2 and 1.3.
Rationale for Requirement R2: R2 establishes a uniform continent-wide contingency
reserve requirement. R2 establishes a requirement that contingency reserve be at least
equal to the applicable entity’s Most Severe Single Contingency. By including a definition
of Most Severe Single Contingency and R2, a consistent uniform continent-wide
contingency reserve requirement has been established. Its goal is to assure that the
Responsible Entity will have sufficient contingency reserve that can be deployed to meet
R1.
FERC Order 693 (at P356) directed BAL-002 to be developed as a continent-wide
contingency reserve policy. R2 fulfills the requirement associated with the required
amount of contingency reserve a Responsible Entity must have available to respond to a
Reportable Balancing Contingency Event. Within FERC Order 693 (at P336) the
Commission noted that the appropriate mix of operating reserve, spinning reserve and
non-spinning reserve should be addressed. However, the Order predated the approval of
the new BAL-003, which addresses frequency responsive reserve and the amount of
frequency response obligation. With the development of BAL-003, and the associated
reliability performance requirement, the SDT believes that, with R2 of BAL-002 and the
approval of BAL-003, the Commission’s goals of a continent-wide contingency reserves
policy is met. The suites of BAL standards (BAL-001, BAL-002, and BAL-003) are all
performance-based. With the suite of standards and the specific requirements within
each respective standard, a continent-wide contingency policy is established.
In the Violation Severity Levels for Requirement R1, the impact of the Responsible Entity
recovering from a Reportable Balancing Contingency Event depends on the amount of its
Contingency Reserve available and whether it has sufficient response. Additionally, the
drafting team understands that the Responsible Entity’s available Contingency Reserve
may vary slightly from MSSC at any time. This variability is recognized in Requirement R2
through averaging the available Contingency Reserve over each Clock Hour.
The ideal goal of maintaining an amount of Contingency Reserve to cover the Most
Severe Single Contingency at all times is not necessarily in the best interest of reliability.
It may have the unintended result of tying operators' hands by removing use of their

Posting 6 of Standard: January, 2015

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BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

available contingency reserve from their toolbox in order to maintain service to load or
manage other reliability issues. By allowing for the occasional use of this minimal amount
of Contingency Reserve at the operators' discretion for other contingencies, reliability is
enhanced. The SDT crafted the proposed standard to encourage the operators to use, at
their discretion and within the limits set forth in the standard, their available contingency
reserve to best serve reliability in Real-time. The last thing that anyone desires is to have
Contingency Reserve held available and the lights go off because the standard would
penalize the operator for using the Contingency Reserve to maintain service to the load.
However, the drafting team did not believe that the use of reserves for issues other than
a Reportable Balancing Contingency Event should be unbounded. The SDT limited the use
of Contingency Reserve.
R2. The Responsible Entity shall maintain Contingency Reserve, averaged over each Clock
Hour, greater than or equal to its average Clock Hour Most Severe Single Contingency,
except during one or more of the following periods when the Responsible Entity is in:
[Violation Risk Factor: Medium] [Time Horizon: Real-time Operations]
2.1 using its Contingency Reserve, for a period not to exceed 90 minutes,
to mitigate the reliability concerns associated with Contingencies that
are not Balancing Contingency Events; and/or
2.2 using its Contingency Reserve, for a period not to exceed 90 minutes,
to respond to an Operating Instruction requiring the use of
Contingency Reserve; and/or
2.3 using its Contingency Reserve for a period not to exceed 90 minutes,
to resolve the exceedance of a System Operating Limit (SOL) or
Interconnection Reliability Operation Limit (IROL) that requires the
use of Contingency Reserve; and/or
2.4 in a Contingency Reserve Restoration Period; and/or
2.5 in a Contingency Event Recovery Period; and/or
2.6 in an Energy Emergency Alert Level under which the Responsible
Entity no longer has required Contingency Reserve available provided
that the Responsible Entity has made preparations for interruption of
Firm Load to replace the shortfall of Contingency Reserve to avoid the
uncontrolled failure of components or cascading outages of the
Interconnection. For this exemption to apply, the preparations must
be initiated within 5 minutes from the time that the Energy
Emergency Alert Level is declared.
M2. Each Responsible Entity shall have dated documentation that demonstrates
compliance with Requirement R2., e Evidence of compliance may include, but is not
limited to, documenting Contingencies and Energy Emergency Alert Levels through
outage records, an Energy Emergency Alert Level under which Contingency Reserves
have been activated with communication from their RC, operator logs, and others.

Posting 6 of Standard: January, 2015

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BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

Compliance may be achieved by demonstrating that:
x

Contingency Reserve, averaged over each Clock Hour, meets or exceeds the
required Contingency Reserve; or,

x

Contingency Reserve has been restored to the required Contingency Reserve
levels within the specified period: or,

x

the sum of the Contingency Reserve and Firm Load available as a substitute for
unavailable Contingency Reserve reaches the required Contingency Reserve
level within the specified period;
Any shortfall from compliance will be measured as compliance of 100% minus
the shortfall’s percentage share of MSSC.

If the recording of Contingency Reserve or MSSC is interrupted such that more than
50 percent of the samples within the clock hour are invalid data, then that clock hour
is excluded from evaluation. If any portion of the Clock Hour is excluded by rule in
Requirement R2, then compliance with that portion of the hour not excluded may be
shown by either determination of the integrated value for that portion of the hour
not excluded by the rule or an instantaneous value showing reserves any time during
the excluded period.

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 Responsible Entity shall retain data or evidence to show compliance for
the current year, plus three previous calendar years, unless directed by its

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BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

Compliance Enforcement Authority to retain specific evidence for a longer
period of time as part of an investigation.
If a Responsible Entity is found noncompliant, it shall keep information related
to the noncompliance until found compliant, or for the time period specified
above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and
all subsequent requested and submitted records.
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. Compliance Audits
Self-Certifications
Spot Checking
Compliance Investigations
Self-Reporting
Complaints
1.5.1.4. Additional Compliance Information
The Responsible Entity may use Contingency Reserve for any Balancing
Contingency Event and as required for any other applicable standards.
A Responsible Entity is not subject to compliance with this standard in any
period during which the Responsible Entity is in an Energy Emergency Alert
Level under which Contingency Reserves have been activated.

Posting 6 of Standard: January, 2015

Page 10 of 15

Real-time
Operations

Real-time
Operations

R1.

R2.

Lower VSL

Medium The Responsible Entity
had Contingency

The Responsible Entity
failed to use CR Form 1
to document a
Reportable Balancing
Contingency Event.

OR

Medium The Responsible Entity
recovered partially
from a Reportable
Balancing Contingency
Event during the
Contingency Event
Recovery Period but
recovered less than
100% but more than
90% of required
recovery from a
Reportable Balancing
Contingency Event
during the
Contingency Event
Recovery Period

VRF

Draft # of Standard: Date Submitted for Posting

Time
Horizon

R#

Table of Compliance Elements

The Responsible Entity
had Contingency

The Responsible Entity
recovered partially
from a Reportable
Balancing Contingency
Event during the
Contingency Event
Recovery Period but
recovered 90% or less
but more than 80% of
required recovery
from a Reportable
Balancing Contingency
Event during the
Contingency Event
Recovery Period.

Moderate VSL

The Responsible Entity
had Contingency

The Responsible Entity
recovered partially
from a Reportable
Balancing Contingency
Event during the
Contingency Event
Recovery Period but
recovered 80% or less
but more than 70% of
required recovery
from a Reportable
Balancing Contingency
Event during the
Contingency Event
Recovery Period.

High VSL

Violation Severity Levels

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event

Page 11 of 15

The Responsible Entity
did not have

The Responsible Entity
recovered 70% or less
of required recovery
during the
Contingency Event
Recovery Period.

Severe VSL

Reserve but the Clock
Hour average amount
of Contingency
Reserve was less than
90% of MSSC but was
greater than or equal
to 80% of MSSC as
averaged over the
Clock Hour.

Reserve but the Clock
Hour average amount
of Contingency
Reserve was less than
80% of MSSC but was
greater than or equal
to 70% of MSSC as
averaged over the
Clock Hour.

August 8, 2005

0

Action

Removed “Proposed” from Effective Date

Effective Date

Draft # of Standard: Date Submitted for Posting

April 1, 2005

Date

0

Version

Version History

CR Form 1

Errata

New

Page 12 of 15

Contingency Reserve
that was equal to or
greater than 70% of
MSSC averaged over
the Clock Hour.

Change Tracking

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event Background Document

F. Associated Documents

None.

E. Interpretations

None.

D. Regional Variances

Reserve but the Clock
Hour average amount
of Contingency
Reserve was less than
100% of MSSC but was
greater than or equal
to 90% of MSSC as
averaged over the
Clock Hour.

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event

February 14,
2006
NERC BOT Adoption

Revised graph on page 3, “10 min.” to “Recovery
time.” Removed fourth bullet.
Complete revision

Errata

Draft # of Standard: Date Submitted for Posting

R10.

Page 13 of 15

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.
R9.

R8.

R7.

R6.

R5.

R4.

R3.

R2.

2

0

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event

Supplemental Material
[Application Guidelines, Guidelines and Technical Basis, Training Material,
Reference Material and/or other Supplemental Material]
R11.

Draft # of Standard: Date Submitted for Posting

Page 14 of 15

Supplemental Material
Rationale
R12. Upon Board approval, the text from the rationale boxes will be moved to this section.
R13.

Draft # of Standard: Date Submitted for Posting

Page 15 of 15

Implementation Plan

Project 2010-14.1 Balancing Authority Reliability-based Controls
- Reserves
Implementation Plan for BAL-002-2 – Disturbance Control Performance - Contingency Reserve for
Recovery from a Balancing Contingency Event
Approvals Required
BAL-002-2 – Disturbance Control Performance - Contingency Reserve for Recovery from a Balancing
Contingency Event
Prerequisite Approvals
None
Revisions to Glossary Terms
The following definitions shall become effective when BAL-002-2 becomes effective:
Balancing Contingency Event: Any single event described in Subsections (A), (B), or (C) below, or
any series of such otherwise single events, with each separated from the next by less than one
minute.
A. Sudden loss of generation:
a. Due to
i. Unit tripping,
ii. Loss of generator Facility resulting in isolation of the generator from the Bulk
Electric System or from the responsible entity’s electric system, or
iii. Sudden unplanned outage of transmission Facility;
b. And, that causes an unexpected change to the responsible entity’s ACE;
B. Sudden loss of an Import, due to forced outage of transmission equipment that causes an
unexpected imbalance between generation and load on the Interconnection.
C. Sudden restoration of a load that was used as a resource that causes an unexpected change
to the responsible entity’s ACE.
Most Severe Single Contingency (MSSC): The Balancing Contingency Event, due to a single
contingency, that would result in the greatest loss (measured in MW) of resource output used by

the Reserve Sharing Group (RSG) or a Balancing Authority that is not participating as a member of a
RSG at the time of the event to meet firm system load and export obligation (excluding export
obligation for which Contingency Reserve obligations are being met by the Sink Balancing
Authority).
Reportable Balancing Contingency Event: Any Balancing Contingency Event resulting in a loss of
MW output less than or equal to the Most Severe Single Contingency, and greater than or equal to
the lesser amount of: (i) 80% of the Most Severe Single Contingency, or (ii) the amount listed below
for the applicable Interconnection, and occurring within a one-minute interval of the initial sudden
decline in ACE based on EMS scan rate data. Prior to any given calendar quarter, the 80% threshold
may be reduced by the responsible entity upon written notification to the Regional Entity.
x

Eastern Interconnection – 900 MW

x

Western Interconnection – 500 MW

x

ERCOT – 800 MW

x

Quebec – 500 MW

Contingency Event Recovery Period: A period beginning at the time that the resource output
begins to decline within the first one-minute interval that defines a Balancing Contingency Event,
and extends for fifteen minutes thereafter.
Contingency Reserve Restoration Period: A period not exceeding 90 minutes following the end of
the Contingency Event Recovery Period.
Pre-Reporting Contingency Event ACE Value: The average value of Reporting ACE, or Reserve
Sharing Group Reporting ACE when applicable, in the 16-second interval immediately prior to the
start of the Contingency Event Recovery Period based on EMS scan rate data.
Reserve Sharing Group Reporting ACE: At any given time of measurement for the applicable
Reserve Sharing Group, the algebraic sum of the ACEs (or equivalent as calculated at such time of
measurement) of the Balancing Authorities participating in the Reserve Sharing Group at the time
of measurement.
Contingency Reserve: The provision of capacity that may be deployed by the Balancing Authority to
respond to a Balancing Contingency Event and other contingency requirements (such as Energy
Emergency Alerts as specified in the associated EOP standard). The capacity may be provided by
resources such as Demand-Side Management (DSM), Interruptible Load and unloaded generation.

Applicable Entities

BAL-002-2 – Disturbance Control Performance - Contingency Reserve for Recovery from a Balancing Contingency Event
January 2015

2

Balancing Authority
Reserve Sharing Group
Applicable Facilities
N/A
Conforming Changes to Other Standards
None
Effective Dates
BAL-002-2 shall become effective as follows:
The first day of the first calendar quarter that is six months after the date that this standard is
approved by applicable 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 six months after the date
the standard is adopted by the NERC Board of Trustees’, or as otherwise provided for in that
jurisdiction.
Justification
The six-month period for implementation of BAL-002-2 will provide ample time for Balancing
Authorities to make necessary modifications to existing software programs to ensure compliance.
Retirements
BAL-002-0, Disturbance Control Performance, and BAL-002-1, Disturbance Control Performance should
be retired at midnight of the day immediately prior to the Effective Date of BAL-002-2 in the particular
jurisdiction in which the new standard is becoming effective.

BAL-002-2 – Disturbance Control Performance - Contingency Reserve for Recovery from a Balancing Contingency Event
January 2015

3

Implementation Plan

Project 2010-14.1 Balancing Authority Reliability-based Controls
- Reserves
Implementation Plan for BAL-002-2 – Disturbance Control Performance - Contingency Reserve for
Recovery from a Balancing Contingency Event
Approvals Required
BAL-002-2 – Disturbance Control Performance - Contingency Reserve for Recovery from a Balancing
Contingency Event
Prerequisite Approvals
None
Revisions to Glossary Terms
The following definitions shall become effective when BAL-002-2 becomes effective:
Balancing Contingency Event: Any single event described in Subsections (A), (B), or (C) below, or
any series of such otherwise single events, with each separated from the next by less than one
minute.
A. Sudden loss of generation:
a. Due to
i. Unit tripping,
ii. Loss of generator Interconnection Facility resulting in isolation of the
generator from the Bulk Electric System or from the responsible entity’s
electric system, or
iii. Sudden unplanned outage of transmission Facility;
b. And, that causes an unexpected change to the responsible entity’s ACE;
B. Sudden loss of an Import, due to forced outage of transmission equipment that causes an
unexpected imbalance between generation and load on the Interconnection.
C. Sudden restoration of a load that was used as a resource that causes an unexpected change
to the responsible entity’s ACE.

Most Severe Single Contingency (MSSC): The Balancing Contingency Event, due to a single
contingency, that would result in the greatest loss (measured in MW) of resource output used by
the Reserve Sharing Group (RSG) or a Balancing Authority that is not participating as a member of a
RSG at the time of the event to meet firm system load and export obligation (excluding export
obligation for which Contingency Reserve obligations are being met by the sSink Balancing
Authority).
Reportable Balancing Contingency Event: Any Balancing Contingency Event resulting in a loss of
MW output less than or equal to the Most Severe Single Contingency, and greater than or equal to
the lesser amount of: (i) 80% of the Most Severe Single Contingency, or (ii) the amount listed below
for the applicable Interconnection, and occurring within a one-minute interval of the initial sudden
decline in ACE based on EMS scan rate data. Prior to any given calendar quarter, the 80% threshold
may be reduced by the responsible entity upon written notification to the Regional Entity.
x

Eastern Interconnection – 900 MW

x

Western Interconnection – 500 MW

x

ERCOT – 800 MW

x

Quebec – 500 MW

Contingency Event Recovery Period: A period beginning at the time that the resource output
begins to decline within the first one-minute interval that defines a Balancing Contingency Event,
and extends for fifteen minutes thereafter.
Contingency Reserve Restoration Period: A period not exceeding 90 minutes following the end of
the Contingency Event Recovery Period.
Pre-Reporting Contingency Event ACE Value: The average value of Reporting ACE, or Reserve
Sharing Group Reporting ACE when applicable, in the 16 -second interval immediately prior to the
start of the Contingency Event Recovery Period based on EMS scan rate data.
Reserve Sharing Group Reporting ACE: At any given time of measurement for the applicable
Reserve Sharing Group, the algebraic sum of the ACEs (or equivalent as calculated at such time of
measurement) of the Balancing Authorities participating in the Reserve Sharing Group at the time
of measurement.
Contingency Reserve: The provision of capacity that may be deployed by the Balancing Authority to
respond to a Balancing Contingency Event and other contingency requirements (such as Energy
Emergency Alerts as specified in the associated EOP standard). The capacity may be provided by
resources such as Demand- Side Management (DSM), Interruptible Load and unloaded generation.

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Applicable Entities
Balancing Authority
Reserve Sharing Group
Applicable Facilities
N/A
Conforming Changes to Other Standards
None
Effective Dates
BAL-002-2 shall become effective as follows:
The first day of the first calendar quarter that is six months after the date that this standard is
approved by applicable 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 six months after the date
the standard is adopted by the NERC Board of Trustees’, or as otherwise provided for in that
jurisdiction.
Justification
The six-month period for implementation of BAL-002-2 will provide ample time for Balancing
Authorities to make necessary modifications to existing software programs to ensure compliance.
Retirements
BAL-002-0, Disturbance Control Performance, and BAL-002-1, Disturbance Control Performance should
be retired at midnight of the day immediately prior to the Effective Date of BAL-002-2 in the particular
jurisdiction in which the new standard is becoming effective.

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Comment Form

Project 2010-14.1 Balancing Authority Reliability-based Control

BAL-002-2 – Disturbance Control Performance - Contingency Reserve for
Recovery from a Balancing Contingency Event

Please do not use this form to submit comments on the proposed revisions to BAL-002-2 Disturbance
Control Performance - Contingency Reserve for Recovery from a Balancing Contingency Event.
Comments must be submitted using the electronic comment form by 8 p.m. March 16, 2015. If you
have questions please contact Darrel Richardson (email) or by telephone at (609) 613-1848.
Background Information:

Since loss of generation occurrences so often impacts all Balancing Authorities throughout an
Interconnection, BAL-002 was created to specify recovery actions and time frames. The original
Standards Authorization Request (SAR) approved by the Industry presumes there is presently sufficient
contingency reserve in all the North American Interconnections. The underlying goal of the SAR was to
update the Standard to make the measurement process more objective and to provide information to
the Balancing Authority or Reserve Sharing Group such that the parties would better understand the
use of contingency reserve to balance resources and demand following a Reportable Contingency
Event. The primary objective of BAL-002-2 is to measure the success of recovering from contingency
events.
Based on comments received from industry stakeholders the drafting team made the following
modifications to the draft standard.
x Modified Requirement R1 to provide additional clarity.
x Modified Requirement R2 and Measure M2 to provide additional clarity and allow for the use of
Contingency Reserve for other than a Balancing Contingency Event. Also, defined other uses for
Contingency Reserves.
x Added rationale supporting Requirements R1 and R2.
x Modified the BAL-002-2 Background Document.
o Modified the body of the document to provide additional clarity.
o Modified the charts in Attachment 1 to use only loss of resource events and added
events for 2014.
o Added examples for compliance to Requirement R1.
o Added Attachment 3 which discusses use of Contingency Reserves during an Energy
Emergency Alert.

You do not have to answer all questions. Enter All Comments in Simple Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Please provide any issues you have on this draft of the BAL-002-2 standard and a proposed
solution.
Comments:

BAL-002-2 Disturbance Control Performance - Contingency Reserve for Recovery from a Balancing Contingency Event
Comment Form

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BAL-002-2
Background Document
January 2015

BALͲ002Ͳ2ͲBackgroundDocument
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Table of Contents


Introduction .................................................................................................................................... 3
RationalebyRequirement .............................................................................................................. 7
Requirement1 ................................................................................................................................ 7
Requirement2 .............................................................................................................................. 15


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DisturbanceControlPerformanceͲContingencyReserveforRecoveryFromaBalancing
ContingencyEventStandardBackgroundDocument

Introduction
TherevisiontoNERCPolicyStandardsin1996createdaDisturbanceControlStandard(DCS).It
replacedB1[AreaControlError(ACE)mustreturntozerowithin10minutesfollowinga
disturbance]andB2(ACEmuststarttoreturntozeroin1minutefollowingadisturbance)with
astandardthatstates:ACEmustreturntoeitherzeroorapreͲdisturbancevalueofACEwithin
15minutesfollowingareportabledisturbance.BalancingAuthoritieswererequiredtoreport
alldisturbancesequaltoorgreaterthan80%oftheBalancingAuthority’sMostSevereSingle
Contingency(MSSC).

BALͲ002wascreatedtoreplaceportionsofPolicy1.Itmeasurestheabilityofanapplicable
entitytorecoverfromareportableeventwiththedeploymentofreserve.Thereliable
operationoftheinterconnectedpowersystemrequiresthatadequatecapacityandenergybe
availabletomaintainscheduledfrequencyandavoidlossoffirmloadfollowinglossof
transmissionorgenerationcontingencies.Thiscapacity(ContingencyReserve)isnecessaryto
replacecapacityandenergylostduetoforcedoutagesofgenerationortransmission
equipment.ThedesignofBALͲ002andPolicy1waspredicatedontheInterconnection
operatingundernormalconditions,andtherequirementsofBALͲ002assuredrecoveryfrom
singlecontingency(NͲ1)events.

ThisdocumentprovidesbackgroundonthedevelopmentandimplementationofBALͲ002Ͳ2Ͳ
ContingencyReserveforRecoveryfromaBalancingContingencyEvent.Thisdocumentexplains
therationaleandconsiderationsfortherequirementsandtheirassociatedcompliance
information.BALͲ002Ͳ2wasdevelopedtofulfilltheNERCBalancingAuthorityControls(Project
2007Ͳ05)StandardAuthorizationRequest(SAR),whichincludestheincorporationoftheFERC
Order693directives.TheoriginalSAR,approvedbytheindustry,presumesthereispresently
sufficientContingencyReserveinalltheNorthAmericanInterconnections.Theunderlyinggoal
oftheSARwastoupdatethestandardtomakethemeasurementprocessmoreobjectiveand
toprovideinformationtotheBalancingAuthorityorReserveSharingGroup,suchthatthe
partieswouldbetterunderstandtheuseofContingencyReservetobalanceresourcesand
demandfollowingaReportableBalancingContingencyEvent.

Currently,theexistingBALͲ002Ͳ1standardcontainsRequirementsspecifictoaReserveSharing
Groupwhichthedraftingteambelievesarecommercialinnatureandacontractual
arrangementbetweenthereservesharinggroupparties.BALͲ002Ͳ2isintendedtomeasurethe
successfuldeploymentofcontingencyreservebyresponsibleentities.Relationshipsbetween
theentitiesshouldnotbepartoftheperformancerequirements,butleftuptoacommercial
transaction.
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DisturbanceControlPerformanceͲContingencyReserveforRecoveryFromaBalancing
ContingencyEventStandardBackgroundDocument

Clarityandspecificsareprovidedwithseveralnewdefinitions.Additionally,theBALͲ002Ͳ2
eliminatesanyquestionaboutwhoistheapplicableentityandassuresthattheapplicable
entityisheldresponsiblefortheperformancerequirement.Thedraftingteam’sgoalwasto
haveBALͲ002Ͳ2besolelyaperformancestandard.TheprimaryobjectiveofBALͲ002Ͳ2isto
ensurethattheapplicableentityispreparedtobalanceresourcesanddemandandtoreturnits
ACEtodefinedvalues(subjecttoapplicablelimits)followingaReportableBalancing
ContingencyEvent.

Asproposed,thisstandardisnotintendedtoaddresseventsgreaterthanaResponsibleEntity’s
MostSevereSingleContingency.TheselargemultiͲunitevents,althoughunlikely,dooccur.
ManyinteractionsoccurduringtheseeventsandBalancingAuthoritiesandReserveSharing
Groupsmustreacttotheseevents.However,requiringarecoveryofACEwithinaspecifictime
periodismuchtoosimpleofamethodologytoadequatelyaddressalloftheseinteractions.
ThesuiteofNERCStandardworktogethertoensurethattheInterconnectionsareoperatedin
asafeandreliablemanner.Itisnotjustonestandard,ratheritisthecombinationoftheBALͲ
001Ͳ2standard,(inwhichR2requiresoperationwithinanACEbandwidthbasedon
interconnectionfrequency),TOPͲ007,andEOPͲ002,whichcollectivelyaddressissueswhen
largeeventsoccur.
x

TheBalancingAuthorityACELimit(BAAL)inR2ofBALͲ001Ͳ2looksatInterconnection
frequencytoprovidetheBAarangeinwhichtheBAshouldstrivetooperateaswellas
a30ͲminuteperiodtoaddressinstanceswhentheBAisoutsideofthatrange.Ifan
eventlargerthantheBA’sMSSCoccurs,theBAALwilllikelychangetoamuchtighter
controllimitbasedonthechangeininterconnectionfrequency.The30Ͳminutelimit
undertheBAALallowstheBA(anditsRC)timetoquicklyevaluatethebestcourseof
actionandthenreactinareasonablemanner.BAALalsoensurestheResponsibleEntity
balancesresourcesanddemandwheneventsoccuroflessmagnitudethanaReportable
BalancingContingency.InadditionR1ofBALͲ001Ͳ2requirestheBAtorespondto
assureControlPerformanceStandard1(CPS1)ismet.ThismayprompttheBAto
respondinsomecircumstancesinlessthan10minutes.

x

TheTOPͲ007standardaddressestransmissionlineloading.MembersoftheBALͲ002Ͳ2
draftingteamareawareofinstances(typicallyNͲ2orless)thatcouldcausetransmission
overloadsifcertainunitswerelostandreservesresponded.

x

UnderEOPͲ002,iftheBAdoesnotbelievethatitcanmeetcertainparameters,different
rulesareimplemented.

Becauseofthepotentialforsignificantunintendedconsequencesthatcouldoccurundera
requirementtoactivateallreserves,thedraftingteamrecommendstotheindustrythatthe
revisedBALͲ002Ͳ2onlyaddresseventswhichareplannedfor(NͲ1)andnotanylossof
resource(s)thatwouldexceedMSSC.Therefore,thedefinitionsandRequirementsunderBALͲ
002Ͳ2excludeeventsgreaterthantheMSSC.ThisprovidesclarityofRequirements,supports
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ContingencyEventStandardBackgroundDocument
reliableoperationoftheBulkElectricSystemandallowsotherstandardstoaddresseventsof
greatermagnitudeandcomplexity.

WithinNERC’sStateofReliabilityReport,ALR2Ͳ5“DisturbanceControlEventsGreaterThanthe
MostSevereSingleContingency”hasbeentrackedandreportedsince2006.Fortheperiod
2006to2011therehavebeen90disturbanceeventsthatexceededtheMSSC,withthehighest
inanygivenyearbeing24events.EvaluationofthedataillustrateseventsgreaterthanMSSC
occurveryinfrequently,andthedraftingteambelievestheirexclusionwillnothaveany
adverseimpactonreliability.

ThemetricreportsthenumberofDCSeventsgreaterthanMSSC,regardlessofthesizeofa
BalancingAuthorityorRSGandofthenumberofreportingentitieswithinaRegionalEntity.A
smallBalancingAuthorityorRSGmayhavearelativelysmallMSSC.Assuch,ahighnumberof
DCSeventsgreaterthanMSSCmaynotindicateareliabilityproblemforthereportingRegional
Entity,butmayindicateanissuefortherespectiveBalancingAuthorityorRSG.Inaddition,
eventsgreaterthanMSSCmaynotcauseareliabilityissueforaBA,RSGorRegionalEntitythat
hasmorestringentstandardswhichrequirecontingencyreservegreaterthanMSSC.



Background

ReliablybalancinganInterconnectionrequiresfrequencymanagementandallofitsaspects.
InputstofrequencymanagementincludeTieͲLineBiasControl,AreaControlError(ACE),and
thevariousRequirementsinNERCResourceandDemandBalancingStandards,specificallyBALͲ
001Ͳ2RealPowerBalancingControlPerformanceandBALͲ003Ͳ1FrequencyResponseand
FrequencyBiasSetting.
BalancingContingencyEvent
BALͲ002Ͳ2appliesduringtherealͲtimeoperationstoensuretheBalancingAuthorityorReserve
SharingGroupbalanceresourcesanddemandbyreturningitsAreaControlErrortodefined
valuesfollowingaReportableBalancingContingencyEvent.
ThedraftingteamincludedaspecificdefinitionforaBalancingContingencyEventtoeliminate
anyconfusionandambiguity.ThepriorversionofBALͲ002wasbroadandcouldbeinterpreted
invariouswaysleavingtheabilitytomeasurecomplianceintheeyeofthebeholder.Including
thespecificdefinitionallowstheResponsibleEntitytofullyunderstandhowtoperformand
meetcompliance.Also,FERCOrder693(atP355)directedentitiestoincludeaRequirement
thatmeasuresresponseforanyeventorcontingencythatcausesafrequencydeviation.By
developingaspecificdefinitionthatdepictstheeventscausinganunexpectedchangetothe
ResponsibleEntity’sACE,thenecessaryresponserequirementsassuretheintentoftheFERC
requirementismet.
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MostSevereSingleContingency
TheMostSevereSingleContingency(MSSC)termhasbeenwidelyusedwithintheindustry;
however,ithasneverbeendefined.Inordertoeliminateawiderangeofdefinitions,the
draftingteamhasincludedaspecificdefinitiondesignedtofulfilltheneedsofthestandard.In
addition,inordertomeetFERCOrderNo.693(atP356),todevelopacontinentͲwide
contingencyreservepolicy,itwasnecessarytoestablishadefinitionofMSSC.
WhenanentitydeterminesitsMSSC,thereviewneedstoincludethelargestlossofresource
thatmightoccurforeithergenerationortransmissionloss.Ifthelossoftransmissioncauses
thelossofgenerationandload,thesizeofthateventwouldbethenetchange.Sincethesizeof
aneventwherebothloadandgenerationarelostduetothelossofthetransmissionwouldbe
lessthanjustthelossofthegenerator,thiseventisunlikelytobetheentity’sMSSC.Also,note
herethatthedraftingteamremovedthepreviousrequirementtoreviewtheMSSCatleast
annually.AnentityshouldknowwhatitsMSSCisatalltimes.Therefore,anannualreviewisno
longerrequired
ContingencyReserve
Mostsystemoperatorsgenerallyhaveagoodunderstandingoftheneedtobalanceresources
anddemandandreturntheirAreaControlErrortodefinedvaluesfollowingaReportable
BalancingContingencyEvent.However,theexistingContingencyReservedefinitionisfocused
primarilyongenerationandnotsufficientlyonDemandͲSideManagement(DSM).Inorderto
meetFERCOrderNo.693(atP356)toincludearequirementthatexplicitlyallowsDSMtobe
usedasaresourceforcontingencyreserve,thedraftingteamelectedtoexpandthedefinition
ofContingencyReservetoexplicitlyincludecapacityassociatedwithDSM.
Additionally,conflictexistedbetweenBALͲ002andEOPͲ002astowhenanentitycoulddeploy
itscontingencyreserve.EOPͲ002alsoappliesduringtherealͲtimeoperationstimehorizonand
addressescapacityandenergyemergencies.Giventhatanentityand/oreventcantransition
suddenlyfromnormaloperations(BALͲ002)intoemergencyoperations(EOPͲ002),this
transitionalseammustbeexplicitlyaddressedinordertoprovideclaritytoresponsibleentities
regardingtheactionstobetaken.
ToeliminatethepossibleconflictandtoassureBALͲ002andEOPͲ002worktogetherand
complementeachother,thedraftingteamclarifiedtheexistingdefinitionofContingency
Reserve.TheconflictarisessincetheactionsrequiredbyEnergyDeficientEntitiesbefore
declaringeitheranEnergyEmergencyAlert2oranEnergyEmergencyAlert3include
deploymentofallOperatingReservewhichincludesContingencyReserve.AnEnergyDeficient
EntitymayneedtodeclareeitheranEnergyEmergencyAlert2oranEnergyEmergencyAlert3,
withoutincurringaBalancingContingencyEvent.WithoutincurringaBalancingContingency
Event,aResponsibleEntitycannotutilizeitsContingencyReservetotheextentitdropsbelow
MSSCwithoutviolatingNERCStandardBALͲ002Ͳ2.Toresolvethisconflict,thedraftingteam
electedtoallowtheResponsibleEntitytobeexemptfromR2ifinanEnergyEmergencyAlert
LevelunderwhichtheResponsibleEntitynolongerhasrequiredContingencyReserves
availableprovidedthattheResponsibleEntityhasmadepreparationsforinterruptionofFirm
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ContingencyEventStandardBackgroundDocument
LoadtoreplacetheshortfallofContingencyReservetoavoidtheuncontrolledfailureof
componentsorcascadingoutagesoftheInterconnection.Also,toassurethesystemoperator
hasthenecessaryflexibilitytoaddressthetransitionfromnormaloperations(BALͲ002)into
emergencyoperations(EOP)thedraftingteamelectedtoallowtheResponsibleentitytobe
exemptfromR2duringoneormoreofthefollowingperiodswhentheResponsibleEntityis:
x

usingitsContingencyReserveforContingenciesthatarenotBalancing
ContingencyEvents;

x

respondingtoanOperatingInstructionrequiringtheuseofContingencyReserve;

x

resolvingtheexceedanceofaSystemOperatingLimitorIROLthatrequiresthe
useofContingencyReserve;and,

x

inaContingencyEventRecoveryPeriodoritssubsequentContingencyReserve
RestorationPeriod.

ForadditionaltechnicaljustificationforexemptingperiodsfromR2tofacilitatetransitioning
fromnormaloperationsintoemergencyoperationspleaserefertoAttachment3.
ReserveSharingGroupReportingACE
Thedraftingteamelectedtoincludethisdefinitiontoprovideclarityformeasurementof
complianceoftheappropriateResponsibleEntity.Additionally,thisdefinitionisnecessary
sincethedraftingteamhaseliminatedR5.1andR5.2thatareintheexistingstandard.R5.1and
R5.2mixdefinitionswithperformance.Thedraftingteamhasincludedalltheperformance
requirementsintheproposedstandardsR1andR2,andthereforehasaddedthedefinitionof
ReserveSharingGroupReportingACE.
OtherDefinitions
Otherdefinitionshavebeenaddedormodifiedtoassureclarificationwithinthestandardand
requirements.


RationalebyRequirement


Requirement1
TheResponsibleEntityexperiencingaReportableBalancingContingencyEventshall,within
theContingencyEventRecoveryPeriod,demonstraterecoverybyreturningits
ReportingACEtoatleasttherecoveryvalueof:

o Zero(ifitsPreͲReportingContingencyEventACEValuewaspositiveorequal
tozero);however,duringtheContingencyEventRecoveryPeriod,any
BalancingContingencyEventthatoccursshallreducetherequiredrecovery:
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ContingencyEventStandardBackgroundDocument
(i)beginningatthetimeof,and(ii)bythemagnitudeof,eachindividual
BalancingContingencyEvent,
or
o ItsPreͲReportingContingencyEventACEValue,(ifitsPreͲReporting
ContingencyEventACEwasnegative):however,duringtheContingency
EventRecoveryPeriod,anyBalancingContingencyEventthatoccursshall
reducetherequiredrecovery:(i)beginningatthetimeof,and(ii)bythe
magnitudeof,eachindividualBalancingContingencyEvent.
1.1

AllReportableBalancingContingencyEventswillbedocumentedusingCRForm
1.

1.2. AResponsibleEntityisnotsubjecttocompliancewithRequirementR1whenitis
experiencingaReliabilityCoordinatorapprovedEnergyEmergencyAlertLevel
underwhichContingencyReserveshavebeenactivated.
1.3RequirementR1(initsentirety)doesnotapply:
x

(i)whentheResponsibleEntityexperiencesaBalancingContingencyEventthat
exceedsitsMostSevereSingleContingency,or

x

(ii)aftermultipleBalancingContingencyEventsforwhichthecombined
magnitudeexceedstheResponsibleEntity’sMostSevereSingleContingencyfor
thoseeventsthatoccurwithinthat105minuteperiod.



BackgroundandRationale
RequirementR1reflectstheoperatingprinciplesfirstestablishedbyNERCPolicy1.Its
objectiveistoassuretheResponsibleEntitybalancesresourcesanddemandandreturnsits
ReportableAreaControlError(ACE)todefinedvalues(subjecttoapplicablelimits)followinga
ReportableBalancingContingencyEvent.ItrequirestheResponsibleEntitytorecoverfrom
eventsthatwouldbelessthanorequaltotheResponsibleEntity’sMSSC.Itestablishesthe
amountofContingencyReserveandrecoveryandrestorationtimeframestheResponsible
Entitymustdemonstrateinacomplianceevaluation.Itisintendedtoeliminatetheambiguities
andquestionsassociatedwiththeexistingstandard.Inaddition,itallowsResponsibleEntities
tohaveaclearwaytodemonstratecomplianceandsupporttheInterconnectiontothefull
extentofitsMSSC.
Byincludingnewdefinitions,andmodifyingexistingdefinitions,andtheaboveR1,thedrafting
teambelievesithassuccessfullyfulfilledtherequirementsofFERCOrderNo.693(atP356)to
includearequirementthatexplicitlyallowsDSMtobeusedasaresourceforContingency
Reserve.Italsorecognizesthatthelossoftransmissionaswellasgenerationmayrequirethe
deploymentofContingencyReserve.
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ContingencyEventStandardBackgroundDocument
Additionally,R1isdesignedtoassuretheapplicableentityusesreservetocoveraReportable
BalancingContingencyEventorthecombinationofanypreviousBalancingContingencyEvents
thathaveoccurredwithinthespecifiedperiod,toaddresstheOrder’sconcernthatthe
applicableentityisrespondingtoeventsandperformanceismeasured.TheReportable
BalancingContingencyEventdefinition,alongwithR1allowsformeasurementofperformance.
ThedraftingteamhasincludedAttachment2illustratinganexampleofthecalculationfor
RequirementR1.
Inaddition,thestandarddraftingteam(SDT)throughR1Parts1.2and1.3hasclearlyidentified
whenR1isnotapplicable.ByincludingR1Part1.2,theproposedstandardeliminatesthe
existingconflictwiththeEOPStandardsandfurtheraddressestheoutstandinginterpretation.
ByclearlystatingwhenR1isnotapplicableordoesnotapply,iteliminatesanyauditor
interpretationandallowstheResponsibleEntitytoperformthefunctioninareliablemanner.
AfundamentalgoaloftheSDTistoassuretheResponsibleEntityhasenoughflexibilityto
maintainservicetoloadwhilemanagingreliability.Also,theSDT’sintentistoeliminateany
potentialoverlaporconflictwithanyotherNERCReliabilityStandardtoeliminateduplicative
reporting,andotherissues.
ThedraftingteamuseddatasuppliedbytheConsortiumforElectricReliabilityTechnology
Solutions(CERTS)tohelpdeterminealleventsthathaveanimpactonfrequency.Datathat
wascompiledbyCERTStoprovideinformationonmeasuredfrequencyeventsispresentedin
Attachment1.Analyzingthedata,revealseventsof100MWorgreaterwouldcaptureall
frequencyeventsforallinterconnections.However,ata100MWreportingthreshold,the
numberofeventsreportedwouldsignificantlyincreasewithnoreliabilitygainsince100MWis
morereflectiveoftheoutlyingevents,especiallyonlargerinterconnections.
ThegoalofthedraftingteamwastodesignacontinentͲwidestandardtocapturethemajority
oftheeventsthatimpactfrequency.Afterreviewingthedataandindustrycomments,theSDT
electedtoestablishreportingthresholdminimumsforeachrespectiveInterconnection.This
assurestherequirementsofFERCOrderNo.693aremet.Thereportablethresholdwas
selectedasthelesserof80%oftheapplicableentity’sMostSevereSingleContingencyorthe
followingvaluesforeachrespectiveInterconnection:
x
x
x
x

EasternInterconnection–900MW
WesternInterconnection–500MW
ERCOT–800MW
Quebec–500MW

Additionally,thedraftingteamusedonlylossofresourceeventsforpurposesofdetermining
theabovethresholds.
ViolationSeverityLevels
IntheViolationSeverityLevelsforRequirementR1,theimpactoftheResponsibleEntity
recoveringfromaReportableBalancingContingencyEventdependsonthepercentageof
desiredrecoveryachieved.
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ContingencyEventStandardBackgroundDocument
ComplianceCalculation
ItisimportanttonotethatR1adjuststherequiredrecoveryvalueofReportingACEforany
otherBalancingContingencyEventsthatoccurduringtheContingencyEventRecoveryPeriod.
However,todeterminecompliancewithR1,themeasuredcontingencyreserveresponse
(insteadoftherequiredrecoveryvalueofReportingACE)isadjustedforanyotherBalancing
ContingencyEventsthatoccurduringtheContingencyEventRecoveryPeriod.Bothmethodsof
adjustmentaremathematicallyequivalent.Accordingly,themeasuredcontingencyreserve
responseiscomputedandcomparedwiththeMWlostasfollows(assumingallresourceloss
values,i.e.BalancingContingencyEvents,arepositive)tomeasurecompliance1:
• Themeasuredcontingencyreserveresponseisequaltooneofthefollowing:
o IfthePreͲReportableContingencyEventACEValueisgreaterthanorequal
tozero,thenthemeasuredcontingencyreserveresponseequals(a)the
megawattvalueoftheReportableBalancingContingencyEventplus(b)the
mostpositiveACEvaluewithinitsContingencyEventRecoveryPeriod(and
followingtheoccurrenceofthelastsubsequentevent,ifany)plus(c)the
sumofthemegawattlossesofthesubsequentBalancingContingencyEvents
occurringwithintheContingencyEventRecoveryPeriodoftheReportable
BalancingContingencyEvent.
o IfthePreͲReportableContingencyEventACEValueislessthanzero,thenthe
measuredcontingencyreserveresponseequals(a)themegawattvalueof
theReportableBalancingContingencyEventplus(b)themostpositiveACE
valuewithinitsContingencyEventRecoveryPeriod(andfollowingthe
occurrenceofthelastsubsequentevent,ifany)plus(c)thesumofthe
megawattlossesofsubsequentBalancingContingencyEventsoccurring
withintheContingencyEventRecoveryPeriodoftheReportableBalancing
ContingencyEvent,minus(d)thePreͲReportableContingencyEventACE
Value.
• ComplianceiscomputedasfollowsonCRForm1inordertodocumentall
BalancingContingencyEventsusedincompliancedetermination:

1

Inadjustingfortheadverseimpactofrapidlysucceeding(i.e.“near”)EventsonaResponsibleEntity’sRecovery

fromanEvent,theSDTthoughtitmoreprudenttoadjustforfuturenearEventsratherthanforpastnearEvents
becausethefutureEventsplaceanaddedburdenonperformance,whileadjustingforthepastEventsinstead
lowerstheperformancerequirement.ToadjustforbothfutureandpastEventsamountstodoubledealing
becauseanEventissubsequenttoapriornearEvent,andbothEventswouldbeservingtorelieveRecoveryfrom
eachother.TheSDTallowedonlyfortheextremecaseofexemptingfromrecoverypriornearEventsthat
combinedexceedMSSC.

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DisturbanceControlPerformanceͲContingencyReserveforRecoveryFromaBalancing
ContingencyEventStandardBackgroundDocument
ƒ

Ifthemeasuredcontingencyreserveresponseisgreaterthanor
equaltothemegawattslost,thentheReportableBalancing
ContingencyEventComplianceequals100percent.

ƒ

Ifthemeasuredcontingencyreserveresponseislessthanorequalto
zero,thentheReportableBalancingContingencyEventCompliance
equals0percent.

ƒ

Ifthemeasuredcontingencyreserveresponseislessthanthe
megawattslostbutgreaterthanzero,thentheReportableBalancing
ContingencyEventComplianceequals100%*(1–((megawattslost–
measuredcontingencyreserveresponse)/megawattslost)).


Theabovecomputationscanbeexpressedmathematicallyinthefollowing5sequentialsteps,
labeledas[1Ͳ5],where:
ACE_BEST–mostpositiveACEduringtheContingencyEventRecoveryPeriodoccurringafter
thelastsubsequentevent,ifany(MW)
ACE_PREͲPreͲReportableContingencyEventACEValue(MW)
COMPLIANCEͲReportableBalancingContingencyEventCompliancepercentage(0Ͳ100%)
MEAS_CR_RESPͲmeasuredcontingencyreserveresponsefortheReportableBalancing
ContingencyEvent(MW)
MSSC–MostSevereSingleContingency(MW)
MW_LOSTͲmegawattlossoftheReportableBalancingContingencyEvent(MW)
SUM_SUBSQͲsumofthemegawattlossesofsubsequentBalancingContingencyEvents
occurringwithintheContingencyEventRecoveryPeriodoftheReportableBalancing
ContingencyEvent(MW)

IfACE_PREisgreaterthanorequalto0,then
MEAS_CR_RESP=MW_LOST+ACE_BEST+SUM_SUBSQ[1]

IfACE_PREislessthan0,then
MEAS_CR_RESP=MW_LOST+ACE_BEST+SUM_SUBSQ–ACE_PRE[2]

IfMEAS_CR_RESPisgreaterthanorequaltoMW_LOST,then
COMPLIANCE=100[3]

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IfMEAS_CR_RESPislessthanorequalto0,then
COMPLIANCE=0[4]

IfMEAS_CR_RESPisgreaterthan0,and,MEAS_CR_RESPislessthanMW_LOST,then
COMPLIANCE=100*(1–((MW_LOST–MEAS_CR_RESP)/MW_LOST))[5]


TheDecisionTreeflowdiagramforDCSbelow,providesavisualizationofthelogicflowfora
ReportableBalancingContingencyEvent.Itincludesdecisionblocksforinitialevent
determination,subsequenteventdetermination,andcheckingforMSSCexceedance which
shouldassisttheResponsibleEntitywithEventRecoveryandanalysis.


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BAAL and
IROL

Resource Loss
> Reporting
Threshold

DCS Real
Time


DCS Off
Line
Reporting

N

Sudden?

Y

Start 15
Minute
Recovery



Subsequent
Events?

Y



N

DecisionTreeforDCS

Make Best
Efforts on
Recovery

> MSSC

Adjust
Calculations

Y

13

N

If IROL or
BAAL
Exceeded, Begin
30 Min Recover

Complete
Form

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DisturbanceControlPerformanceͲContingencyReserveforRecoveryFromaBalancing
ContingencyEventStandardBackgroundDocument

Requirement2
R2.TheResponsibleEntityshallmaintainContingencyReserve,averagedovereachClock
Hour,greaterthanorequaltoitsaverageClockHourMostSevereSingle
Contingency,exceptduringoneormoreofthefollowingperiodswhenthe
ResponsibleEntityis:
2.1 usingitsContingencyReserve,foraperiodnottoexceed90minutes,
tomitigatethereliabilityconcernsassociatedwithContingenciesthat
arenotBalancingContingencyEvents;and/or
2.2 usingitsContingencyReserve,foraperiodnottoexceed90minutes,
torespondtoanOperatingInstructionrequiringtheuseof
ContingencyReserve;and/or
2.3 usingitsContingencyReserveforaperiodnottoexceed90minutes,
toresolvetheexceedanceofaSystemOperatingLimit(SOL)or
InterconnectionReliabilityOperationLimit(IROL)thatrequiresthe
useofContingencyReserve;and/or
2.4 inaContingencyReserveRestorationPeriod;and/or
2.5 inaContingencyEventRecoveryPeriod;and/or
2.6 inanEnergyEmergencyAlertLevelunderwhichtheResponsible
EntitynolongerhasrequiredContingencyReserveavailableprovided
thattheResponsibleEntityhasmadepreparationsforinterruptionof
FirmLoadtoreplacetheshortfallofContingencyReservetoavoidthe
uncontrolledfailureofcomponentsorcascadingoutagesofthe
Interconnection.Forthisexemptiontoapply,thepreparationsmust
beinitiatedwithin5minutesfromthetimethattheEnergy
EmergencyAlertLevelisdeclared.
BackgroundandRationale
R2establishesauniformcontinentͲwidecontingencyreserverequirement.R2establishesa
requirementthatcontingencyreservebeatleastequaltotheapplicableentity’sMostSevere
SingleContingency.ByincludingadefinitionofMostSevereSingleContingencyandR2,a
consistentuniformcontinentͲwidecontingencyreserverequirementhasbeenestablished.Its
goalistoassurethattheResponsibleEntitywillhavesufficientcontingencyreservethatcanbe
deployedtomeetR1.
FERCOrder693(atP356)directedBALͲ002tobedevelopedasacontinentͲwidecontingency
reservepolicy.R2fulfillstherequirementassociatedwiththerequiredamountofcontingency
reserveaResponsibleEntitymusthaveavailabletorespondtoaReportableBalancing
ContingencyEvent.WithinFERCOrder693(atP336)theCommissionnotedthatthe
appropriatemixofoperatingreserve,spinningreserveandnonͲspinningreserveshouldbe
addressed.However,theOrderpredatedtheapprovalofthenewBALͲ003,whichaddresses
frequencyresponsivereserveandtheamountoffrequencyresponseobligation.Withthe
developmentofBALͲ003,andtheassociatedreliabilityperformancerequirement,theSDT
believesthat,withR2ofBALͲ002andtheapprovalofBALͲ003,theCommission’sgoalsofa
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continentͲwidecontingencyreservespolicyismet.ThesuitesofBALstandards(BALͲ001,BALͲ
002,andBALͲ003)areallperformanceͲbased.Withthesuiteofstandardsandthespecific
requirementswithineachrespectivestandard,acontinentͲwidecontingencypolicyis
established.
IntheViolationSeverityLevelsforRequirementR1,theimpactoftheResponsibleEntity
recoveringfromaReportableBalancingContingencyEventdependsontheamountofits
ContingencyReserveavailableandwhetherithassufficientresponse.Additionally,thedrafting
teamunderstandsthattheResponsibleEntity’savailableContingencyReservemayvaryslightly
fromMSSCatanytime.ThisvariabilityisrecognizedinRequirementR2throughaveragingthe
availableContingencyReserveovereachClockHour.
TheidealgoalofmaintaininganamountofContingencyReservetocovertheMostSevere
SingleContingencyatalltimesisnotnecessarilyinthebestinterestofreliability.Itmayhave
theunintendedresultoftyingoperators'handsbyremovinguseoftheiravailablecontingency
reservefromtheirtoolboxinordertomaintainservicetoloadormanageotherreliability
issues.ByallowingfortheoccasionaluseofthisminimalamountofContingencyReserveatthe
operators'discretionforothercontingencies,reliabilityisenhanced.TheSDTcraftedthe
proposedstandardtoencouragetheoperatorstouse,attheirdiscretionandwithinthelimits
setforthinthestandard,theiravailablecontingencyreservetobestservereliabilityinRealͲ
time.ThelastthingthatanyonedesiresistohaveContingencyReserveheldavailableandthe
lightsgooffbecausethestandardwouldpenalizetheoperatorforusingtheContingency
Reservetomaintainservicetotheload.However,thedraftingteamdidnotbelievethatthe
useofreservesforissuesotherthanaReportableBalancingContingencyEventshouldbe
unbounded.TheSDTlimitedtheuseofContingencyReserve.


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Attachment 1
NERC Interconnections 2009-2013
Frequency Events Loss MW Statistics

For: NERC BARC Standard Drafting Team
Prepared by: CERTS
Date: October 15, 2013

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ContingencyEventStandardBackgroundDocument

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ContingencyEventStandardBackgroundDocument

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Attachment 2
BAL-002-2 R1 Example

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Requirement1
TheResponsibleEntityexperiencingaReportableBalancingContingencyEventshall,within
theContingencyEventRecoveryPeriod,demonstraterecoverybyreturningits
ReportingACEtoatleasttherecoveryvalueof:[ViolationRiskFactor:Medium][Time
Horizon:RealͲtimeOperations]
o

Zero,(ifitsPreͲReportingContingencyEventACEValuewaspositiveorequal
tozero);however,duringtheContingencyEventRecoveryPeriod,any
BalancingContingencyEventthatoccursshallreducetherequiredrecovery:
(i)beginningatthetimeof,and(ii)bythemagnitudeof,eachindividual
BalancingContingencyEvent,

Or,
o ItsPreͲReportingContingencyEventACEValue,(ifitsPreͲReporting
ContingencyEventACEValuewasnegative);however,duringthe
ContingencyEventRecoveryPeriod,anyBalancingContingencyEventthat
occursshallreducetherequiredrecovery:(i)beginningatthetimeof,and(ii)
bythemagnitudeof,eachindividualBalancingContingencyEvent.
ToillustratetheaboverequirementthefollowingscenarioofthreeBalancingContingency
Events,andcomplianceforeachevent,isprovided.Itisassumedinthisscenariothatthe
reportableeventthresholdis200MW.

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Event1Compliance




x
x
x
x

ResponsibleEntityPreͲReportingContingencyEventACEValueis100MW
TimeoftheBalancingContingencyEventͲ12:05
SizeoftheBalancingContingencyEventͲ900MW
ResponsibleEntityMSSCͲ2,000MW

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x

ResultingResponsibleEntity’sACEValuefollowingtheBalancingContingencyEvent
–negative800MW


WithnoadditionalContingencyEvents,theResponsibleEntitymustdemonstraterecoveryof
Event1byreturningitsReportingACEtoatleasttherecoveryvalueofzerowithinthe
ContingencyEventRecoveryPeriod,orby12:20.

However,iftheResponsibleEntityexperiencedanotherContingencyEvent(Event2)based
uponthefollowing:
x ACEhadrecoveredtonegative350–priortoEvent2
x TimeoftheContingencyEventͲ12:10
x SizeoftheContingencyEventͲ400MW
x ResponsibleEntityReportingACEValueat12:10–negative750

AtthetimeofEvent2,theResponsibleEntitywouldreducethevalueofitsrequiredrecovery
fromtheoriginalBalancingContingencyEvent1bythesizeoftheContingencyEventat12:10
(Event2),thusloweringtherequiredrecoveryvalueofACEtonegative400MW.The
ResponsibleEntitywoulddemonstraterecoveryfromBalancingContingencyEvent1,taking
intoaccountEvent2,byreturningitsReportingACEtoatleastanegative400MWby12:20.

NowiftheResponsibleEntityexperiencedanadditionalContingencyevent(Event3)priorto
12:20namely:
x ACEhadrecoveredtonegative550MW–priortoEvent3
x TimeoftheContingencyEventͲ12:15
x SizeoftheContingencyEventͲ200MW
x ResponsibleEntityReportingACEValueat12:15–negative750

AtthetimeofEvent3,theResponsibleEntitywouldreducethevalueofitsrequiredACE
recoveryfromtheoriginalBalancingContingencyEvent1bythesizeoftheContingencyEvent
at12:10(Event2)andtheContingencyEventat12:15(Event3),thusloweringtherequiredACE
recoveryvaluetonegative600MW.TheResponsibleEntitywoulddemonstraterecoveryfrom
BalancingContingencyEvent1,takingintoaccountEvents2and3byreturningitsReporting
ACEtoatleastanegative600MWby12:20.

TheResponsibleEntitymustshowcomplianceforalleventsthatmightoccurduringthe
ContingencyEventRecoveryPeriod(Event1).Event2andEvent3fromtheexampleabove
woulddemonstratecomplianceinasimilarfashionaswasdemonstratedforEvent1above.
EachwouldhaveitsownuniqueContingencyEventRecoveryPeriodasdefinedbythestartof
therespectivecontingencyevent(i.e.Event2’sContingencyEventRecoveryPeriodwouldbegin
at12:10andendat12:25;Event3’sContingencyEventRecoveryPeriodwouldbeginat12:15
andendat12:30).TherequiredACEValue(0MW)ofrecoveryfromEvents1;therequired
ACEValue(Ͳ200MW)ofRecoveryfromEvent2wouldbetherequiredValue(0MW)of
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RecoveryfromfinalEvent3)minusthesizeofEvent3(200MW),whiletherequiredACEValue
(Ͳ600MW)ofRecoveryfromEvent1wouldbetherequiredValue(0MW)ofRecoveryfrom
finalEvent3minusthesize(600MW)oftheevents2(400MW)&3(200MW)subsequentto
Event1.



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ThefollowingdemonstratesthelogicusedforcompliancewithEvent2(from12:10–12:25,
includingEvent3).
Event2Compliance




ResponsibleEntity’srequiredACEValueofrecoveryfromEvent2is0MW(thesameasitwas
fromthepreͲexistinginitialContingencyEvent1priortoanyadjustmentforEvent2)
x TimeoftheBalancingContingencyEventͲ12:10
x SizeoftheBalancingContingencyEventͲ400MW
x ResponsibleEntityMSSCͲ2,000MW
x ResultingResponsibleEntity’sACEValuefollowingtheBalancingContingencyEvent
–negative750MW
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WithnoadditionalContingencyEvents,theResponsibleEntitymustdemonstraterecovery
fromEvent2byreturningitsReportingACEtoEvent1’sprior,unadjustedPreͲReporting
ContingencyEventACEvalueof0MWwithintheContingencyEventRecoveryPeriod,orby
12:25.

However,theResponsibleEntityexperiencedanotherContingencyEvent(Event3)basedupon
thefollowing:

x ACEhadrecoveredtonegative550–priortoEvent3
x TimeoftheContingencyEventͲ12:15
x SizeoftheContingencyEventͲ200MW
x ResponsibleEntityReportingACEpostContingencyEvent–negative750

AtthetimeofEvent3,theResponsibleEntitywouldreducethevalueofitsrequiredrecovery
fromtheBalancingContingencyEvent2bythesizeofContingencyEvent3at12:15,thus
loweringtherequiredACErecoveryfromEvent2tonegative200MW.TheResponsibleEntity
woulddemonstraterecoveryfrombothBalancingContingencyEvent1andBalancing
ContingencyEvent2,takingintoaccountEvent3,byreturningitsReportingACEtoatleasta
negative200MWby12:30.



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ThefollowingdemonstratesthelogicusedforcompliancefollowingEvent3(from12:15–
12:30).

Event3Compliance



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TheResponsibleEntity’srequiredACEValueofrecoveryfromfinalEvent3is0MW(thesame
asitwasfromtheinitialBalancingContingencyEvent1priortoanysubsequentevents)
x TimeoftheBalancingContingencyEventͲ12:15
x SizeoftheBalancingContingencyEventͲ200MW
x ResponsibleEntityMSSCͲ2,000MW
ResultingResponsibleEntity’sACEValuefollowingtheBalancingContingencyEvent
–negative750MW

WithnoadditionalContingencyEvents,theResponsibleEntitymustdemonstraterecoveryof
finalEvent3byreturningitsReportingACEtothe0MWACEvalueof0MWofrecoveryfrom
theinitialEvent1withintheContingencyEventRecoveryPeriod,orby12:30.

Theaboveexamplesillustratetheminimumresponseforcompliance.Actualeventsand
recoverieswilldifferbecauseofmatterssuchas,butnotlimitedto,ContingencyReservebeing
deployeddifferently.







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Attachment 3
Technical Justification for Applicability
of BAL-002 During Emergency Alerts

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TechnicalJustificationforApplicabilityofBALͲ002
DuringEnergyEmergencyAlerts

I.

INTRODUCTION


TheBalancingAuthorityReliabilityͲbasedControlsstandarddraftingteam(BARCSDT)has
identifiedaconflictbetweenNERCReliabilityStandardsBALͲ002andEOPͲ002that
unnecessarilyrequiresarbitraryinterruptionofFirmLoad.Inordertoaddressthisissue,the
BARCSDTisrecommendingthatStandardBALͲ002Ͳ2notbeenforceableduringanEnergy
EmergencyAlert(EEA)eventwheretheEEAprocessrequirestheuseofContingencyReserveto
maintainloadservice.2Thisdocumentprovidessupportforthisrecommendationandan
overviewofreliablefrequencymanagementontheNorthAmericanInterconnections.

II.
BACKGROUND

ReliablybalancinganInterconnectionrequiresfrequencymanagementandallofitsaspects.
InputstofrequencymanagementincludeTieͲLineBiasControl,AreaControlError(ACE),and
thevariousRequirementsinNERCResourceandDemandBalancingStandards,specificallyBALͲ
001Ͳ2RealPowerBalancingControlPerformanceandBALͲ003Ͳ1FrequencyResponseand
FrequencyBiasSetting.

ReliabilityStandardBALͲ002appliesduringtherealͲtimeoperationstimehorizonand
addressesthebalancingofresourcesanddemandfollowingadisturbance.ReliabilityStandard
EOPͲ002alsoappliesduringtherealͲtimeoperationstimehorizonandaddressescapacityand
energyemergencies.Giventhatanentityand/oreventcantransitionsuddenlyfromnormal
operationsintoemergencyoperations(EOPͲ002)whereContingencyReservemaintainedunder
BALͲ002maybeutilizedtoserveFirmLoad,thistransitionalseammustbeexplicitlyaddressed
inordertoprovideclaritytoresponsibleentitiesregardingtheactionstobetaken.The
proposedapplicabilityofBALͲ002isdesignedtoaddressthisissue.

III.
LEGACYREQUIREMENTS

TheResourceandDemandBalancing(BAL)standardsincludebothrequirementsthathavea
soundtechnicalbasisandlegacyrequirementsthattheindustryhasusedforyearsbutfailto

2

Theproposedapplicabilitysectionstates:“ApplicabilityisdeterminedonanindividualReportableBalancing
ContingencyEventbasis,buttheResponsibleEntityisnotsubjecttocomplianceduringperiodswhenthe
ResponsibleEntityisinanEnergyEmergencyAlertLevelunderwhichContingencyReserveshavebeenactivated.”
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haveasoundtechnicalbasis.NERCbeganreplacingtheselegacyrequirementswithtechnically
basedrequirementsstartingwiththeControlPerformanceStandard1(CPS1).BothControl
PerformanceStandard2(CPS2)andtheDisturbanceControlStandard(DCS)remaininthe
legacycategory.Thefollowingarespecificconcernsassociatedwiththeserequirements.
o WhenCPS1wasimplementedtoreplaceA1/A2,previousrequirementswere
modifiedsothatCPS1wouldapplyatalltimesincludingthe(disturbance)
periodswhereDCSisapplicable,notjustduringnormaloperations/periods.So
DCSisnottheonlystandardgoverningdisturbanceconditions.
o TheDisturbanceControlStandard(DCS)anditsprecursorB1/B2havebeen
uniqueinrequiringimmediateactionbytheBalancingAuthority(BA),inthis
casetoaddressunexpectedimbalanceswithindefinedlimits.
o DCS,albeitresultsͲbasedinitscurrentform,wasinitiallydesignedtomeasure
theutilizationofContingencyReservetoaddressalossofresourcewithinthe
definedlimits.InitsresultsͲbasedformitassumedthatimplementingsufficient
ContingencyReservesasneededtocomplywiththerecoveryrequirement
wouldbeareasonablyequitableminimumquantityforallBAsparticipatingin
interconnectedoperation.
o DCSisbaseduponACErecoverytothelowerofpreͲdisturbanceACEorzero.A
BalancingAuthoritywhichmightbeunderͲgeneratingpriortoagenerationloss,
couldloseageneratingunitandunderDCSbedeemedcompliantifitreturned
ACEtoitspreͲdisturbancestate,thoughitcouldstillbedepressing
Interconnectionfrequency.
o AsDCSrecoveryfromareportableeventmustoccurwithina15Ͳminuteperiod,
itispossibleforaBalancingAuthority’sACEtoagaingonegativeafterthattime,
withasimilarimpactonInterconnectionfrequency.
o SinceCPS2allowsaBAtobeunaccountableforapproximately74hoursof
operationina31Ͳdaymonth,animbalanceconditionmaypersistandnegatively
impactInterconnectionfrequencyformanyhours3.
o WhenACEismodulatedbyfrequency,“significant”lossesaredefinednotonly
bythesizeoftheeventcausinganACEdeviation,butalsocontingentonthe
deviationofInterconnectionfrequencyfromScheduledFrequency.

IV.
TIEͲLINEBIASFREQUENCYCONTROLANDACE


3

ReliabilityͲBasedControlv3,StandardAuthorizationRequestForm,November7,2007.

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TieͲLineBiasFrequencyControlisimplementedontheNorthAmericanInterconnections
throughtheuseoftheACEEquation.4Ingeneral,ACEisthetermusedtodeterminetheloadͲ
generationimbalancethatisbeingcontributedbyeachBalancingAuthority(BA)onan
Interconnection.ACEisapowerfulindicator,becauseitindicatestheimbalancewithinthe
boundariesofasingleBA,thusdefiningtheSecondaryControlresponsibilitiesforthatBAand,
therefore,thecontrolactionthatwouldreturnACEtozero.ACEincludestheFrequencyBias
Settingterm,whichallowsthePrimaryFrequencyControltobeasharedservicethroughouta
multiͲBAInterconnection,whileassigningtoeachindividualBAthespecificresponsibilitiesof
maintainingitsownSecondaryFrequencyControl.

Insummary,ACEonlyprovidesguidancewithrespecttoSecondaryFrequencyControland
doesnotindicateorprovideanydirectmeasureofPrimaryFrequencyControl,andonlyreflects
theestimatedFrequencyResponseasrepresentedbytheFrequencyBiasSettingterm.NERC
RequirementsandsupportingdocumentationforFrequencyResponse(PrimaryFrequency
Control)areincludedinBALͲ003Ͳ1FrequencyResponseandFrequencyBiasSettingstandard.
MoredetailonTieͲLineBiasFrequencyControlandACEisattached.5

V.
CONTROLPERFORMANCESTANDARD1(CPS1)

PriortothedevelopmentofCPS1,theindustryassumedthat,"Itisimpossible,however,to
usefrequencydeviationtoidentifythespecificcontrolarea(sic,i.e.BA)withtheunderͲor
overͲgenerationcreatingthefrequencydeviation…".3Inthe1990'sthedevelopmentofCPS1
demonstratedthatnotonlywasitpossibletoidentifythespecificBAcreatingthefrequency
deviation,butthatitisalsopossiblenotonlytodeterminetherelativecontributionbyeachBA
tothemagnitudeofthefrequencydeviation6,butalsotodeterminetherelativecontributionof
eachBAtothereliabilityriskcausedbythatdeviation.Inaddition,theCPS1Requirement
providedaguarantee:"IfallBAsonaninterconnectioncompliedwiththeCPS1Requirement,

4

Illian,HowardF.,UnderstandingACE,CPS1andBAAL,PreparedfortheNERCBARCStandardDraftingTeam,
September10,2010rev.August19,2014,Section2,pp.1Ͳ4,foraderivationoftheACEEquationandthe
requirementsforimplementingitthatareincludedinthedefinitionofACEappearingintheNERCGlossary.

5

Illian, Howard F., Frequency Control Performance Measurement and Requirements, Ernest
Orlando Lawrence Berkeley National Laboratory, December 2010, for a discussion of the
history of Frequency Control and Performance Measurement.

6

Illian, Howard F., Understanding ACE, CPS1 and BAAL, Section 2, pp. 5-10 for a derivation
of the CPS1 requirement.

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theRootMeanSquared7valueofthefrequencydeviationforthatInterconnectionwouldbe
lessthantheepsilon18frequencydeviationlimitforthatInterconnection."

CPS1isarollingannualaverageofindividualmeasurementseachaveragedoveroneͲ
minute,andisassessedmonthly.CPS1measuresthecovariancebetweentheACEofaBAand
thefrequencydeviationoftheInterconnectionwhichisequaltothesumoftheACEsofallof
theBAs.CPS1hasthegreatvalueofusingtheInterconnectionfrequencytodeterminethe
degreetowhichACEamongtheBAsonamultipleBAInterconnectionisharmingorhelping
interconnectionfrequency.Sincethefrequencydeviationisameasuredvalue,theACEofaBA
willdirectlyaffectonlytheCPS1oftheBAwiththeACEandnottheCPS1measureofotherBAs.

VI.
BALANCINGAUTHORITYACELIMIT(BAAL)

WhentheBalancingResourcesandDemand(BRD)standarddraftingteamrecognizedthe
needforacontrolmeasureoverashortertimehorizonthaneitherCPS1(annual)orControl
PerformanceStandard29(CPS2,monthly)provided,itbeganlookingforameasurethatwould
allowawindowforcommonimbalanceeventslikeaunittrip,whileprovidingalimitonhow
muchfrequencydeviationshouldbeallowedoverthatshortperiod.Afterconsidering
numerousalternatives,BAALwasselectedastheappropriateshortͲtermmeasure.10,11


7

“Root Mean Squared” means the square root of the mean of the squared errors, so that
positive and negative errors do not offset each other and any shift in the mean is counted
as error.

8

“Epsilon1” is the frequency deviation limit determined for each North American
Interconnection and used by CPS1 to bound the Root Mean Squared frequency deviation.
It is 18 mHz on the Eastern, 22.8 mHz on the Western, 30 mHz on the ERCOT, and 21
mHz on the Quebec Interconnections.

9

Proposed to be replaced by BAAL under BAL-001-2, CPS2 requires the BA to move its ACE
within predefined L10 bounds when it is binding (during only 90% of the ten-minute
periods per month) without regard to whether such action helps or hurts Interconnection
frequency.

10

Illian, Howard F., Meeting the Discrete Event Measure (DEM) Objectives with the
Abnormal Operations Measure (AOM), Prepared for the NERC Balancing Resources and
Demand Standard Drafting Team, March 20, 2004.

11

Illian, Howard F., Setting the Balancing Authority ACE Limit (BAAL) for the NERC
Abnormal Operations Measure (AOM), Prepared for the NERC Balancing Resources and
Demand Standard Drafting Team, March 28, 2004.

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ConsiderableevaluationandFieldTrialshaveshownthatBAAL12isabetterindicatorof
contributionstoreliabilityriskofaninterconnectionthanthemagnitudeofACEalone.This
superiority,likeCPS1’s,derivesfromtheconcurrentuseofbothACEandfrequencyerrorinthe
BAALmeasure.ThusBAALcapturestherelativecontributiontoreliabilitybyalloftheACEson
aninterconnectionandindicateswhereeachBAstandsrelativetoitssecondarycontrol
responsibilitiesandthecurrentstateoftheinterconnectionasindicatedbythefrequencyerror
forbothunderͲandoverͲfrequencyconditions.

VII.
INTERACTIONBETWEENSTANDARDS

Thedraftingteamhasidentifiedasanissuetheexistenceofpointswherethestandardsare
inconflictwitheachother.Thedraftingteamhasattemptedtoaddresstheconflictsidentified,
asfollows:

NERCstandardEOPͲ002requiresaBAtouseallitsreservesduringanEnergyEmergency
Alert2(EEA2)orhigher.ThefollowinglanguageisfoundinEOPͲ002Attachment1ͲEOPͲ002:
2.6.4OperatingReserves.Operatingreservesarebeingutilizedsuchthatthe
EnergyDeficientEntityiscarryingreservesbelowtherequiredminimumor
hasinitiatedemergencyassistancethroughitsoperatingreservesharing
program.

ThecurrentBALͲ002specifiesaminimumlevelreserverequirementatalltimesunlessa
qualifyingeventhasoccurred.ThedraftingteamnotedthatintheEEAprocessanentityis
driventorequestanEEArarelyastheresultofasingleunitloss.Infact,anEEAdeclarationby
theReliabilityCoordinatormightresultfromissuesthatincludenoeventthatwouldqualifyas
aDisturbanceandtheEEAsituationcouldlastlongerthanthereserverecoveryperiodof90
minutes.Forthisreason,thedraftingteamrecommendssignificantchangestothestandardsin
question.

Inadditiontotheidentifiedconflict,otherstandardscanrequiretheactivationof
contingencyreserve.TheseincludeotherBALstandards,IROstandardsandTOPstandards.
Comparedtothosestandards,theBALͲ002standardprovidestheleastdirectmeasureof
reliability.Therefore,anentityshouldneverbeconflictedbetweenapplyingtherequirements
ofBALͲ002andcomplyingwiththeotherstandards.


12

Illian, Howard F., Understanding ACE, CPS1 and BAAL, Prepared for the NERC BARC
Standard Drafting Team, September 10, 2010 rev. August 19, 2014, Section 2, pp. 10, for
a derivation of the BAAL requirement.

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Finally,thereisoneoverarchingprincipalnotreflectedinthediscussionuptothispoint,
namelykeepingthelightsonifpossible.IfthereisarequirementtobringACEbacknomatter
what,thenthatrequirementwillhavetheunintendedconsequenceofsheddingFirmLoad,
especiallyduringanEEA.DuringtheEEAprocess,theexpectationisthataBAwillhavefirm
loadreadytoshedinordertomeetitsreserverequirementunderR2oftheproposedBALͲ002
standard.However,iftheBALͲ002standardalsorequirestheentitytomeetR1duringtheEEA,
entitieswillshedfirmloadtorestoreACEtoitspreͲcontingencylevel,regardlessofthelackof
anyreliabilityissues.Inotherwords,frequencycouldbesettlingatorverynear60Hz,no
transmissionlinesareoverloadedasdeterminedbytheTOPstandards,andtheentityis
operatingwithintheparametersdefinedinBALͲ001,butfirmloadwouldbeinterruptedsimply
tobringtheentity’sACEbacktowhatitwaspriortothelossoftheunit.Sincetheindustryhas
definedreliabilityasfrequencyatornear60Hzandtransmissionlinesoperatingwithintheir
limits,thereisnoreasontointerruptfirmload.

Instead,theBARCSDTisrecommendingthatStandardBALͲ002Ͳ2notbeenforceable
duringanEEAeventwheretheEEAprocessrequirestheuseofContingencyReserveto
maintainloadservice.Instead,theReliabilityCoordinator,TransmissionOperatorsandthe
impactedBalancingAuthoritiesshoulduserealͲtimesituationalawareness,takingintoaccount
issuesaddressedinBALͲ001,BALͲ003,theIROsuiteofstandardsandtheTOPsuiteof
standards,todeterminewhatactionsareappropriatewhenconditionsareabnormal.This
processwouldallowcontinuedloadservicewithoutarbitrarilyrequiringinterruptionoffirm
load.

Thisconcernarisesbecausetheotherstandardslookatspecificreliabilityissuesother
thanjustbalancingbetweenscheduledandactualinterchange.BALͲ001Ͳ2andBALͲ003Ͳ1look
atinterconnectionfrequencytodeterminewhethertheBalancingAuthorityishelpingor
hurtingreliability.DuringanEEAevent,curtailingloadtomoveACEbacktoapreͲeventlevel
couldadverselyaffectfrequency.Iffrequencygoesupfrom60HzwhenaBalancingAuthority
interruptsload,theimpactisdetrimentaltotheinterconnection.UndertheTOPstandards,if
flowsontransmissionlinesarewithinthelimitsspecified,thereisnoneedtoaltertheflowson
thetransmissionsystembyinterruptingload.

Finally,theReliabilityCoordinatorhasawideareaviewoftheelectricsystemas
requiredundertheIROstandards.TheIROstandardsclearlystatetheReliabilityCoordinator’s
responsibilitiesduringtheEEAprocess.IftheReliabilityCoordinatorhasnotidentifieda
reliabilityconcerninitsneartermoperationsevaluation,actionssuchasinterruptionoffirm
loadshouldnotoccursimplytobalanceloadandresourceswithintheBA.Duringabnormal
(emergency)situations,takingsignificantactionswithanarrowviewwillnotbebeneficialfor
Interconnectionreliability.

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EXAMPLES
o Example1
OnanusuallycolddayinFebruary2011,at06:22,aBalancingAuthorityArea
(BAA)experienceda350MWgenerationlosswhena750MWjointownership
unittrippedoffͲline.EarlierinthedaytheBAAoperatorexperiencedlossof
severalgeneratingunitswithatotalcapacityof1050MW,thelatestlossbeing
just38minutespriortothe350MWloss.Whenthe350MWeventoccurred
theBAAoperatorrequestedreserve/emergencyassistance,shed300MWof
customerloadtorestorecontingencyreserve,andrequestedtheRCpostan
EEA3.TheEEA3wasposted.Althoughthefrequencyonlytouched59.91Hz,
averaging59.951Hzinthefirstminuteoftheoutage,wasitreallynecessaryto
cutloadandleavepeopleinthecold,darkofthatmorningtorestore
contingencyreserve?Havingidlegeneration,whentheInterconnectionis
operatingreliably,doesnotwarrantsheddingcustomerload.
o Example2
InJune2012,at17:08,aBAAexperiencedan800MWgenerationloss.TheBA
andthereservesharinggroup(RSG)itparticipatesinwereintheprocessof
replacingthelostgenerationwhen,inthethirteenthminuteoftherecovery
whentherewerenoidentifiedfrequency,voltageorloadingthreatstoreliability,
theBAAwasdirectedbyitsReliabilityCoordinator(RC)toshed120MWof
customerload.AlthoughthecombinedAreaControlError(ACE)oftheRSG
participantswaspositive,theRCfocusedontheACEoftheBAAthatlostthe
generation–whichwasstillnegative–ignoringthefactthattheInterconnection
frequency(59.96Hz)wasabovetheFrequencyTriggerLimit(59.932Hz).The
needlesssheddingofcustomerloadwhensystemreliabilityisnotthreatened
attractedtheattentionofstateregulatorswhowerenothappywiththeaction.
ThisdemonstratesthatfocusingsolelyonaBAA’sACEandnotonthetrue
Interconnectionreliabilityindicatorscancauseactionsthatdonotsupport
reliability.
o Example3
InJune2004,at0741,aseriesofeventsledtoagenerationlossofover4,600
MW.Inspiteoftheeventsize,theInterconnectionfrequencywasarrested
withouttriggeringautomaticunderfrequencyloadshedding,thankstogovernor
action,frequencysensitiveloadanddeploymentofContingencyReserve(as
requiredbyBALͲ002).Sometransmissionelementsexceededtheirlimitsfora
shorttime(aspermittedbytheEOPstandards),And,priortothedisturbance,
thefrequencywasinthenormaloperatingrangeduetoautomaticgeneration
control(AGC)operation(asrequiredbyBALͲ001).Duringtheeventalmost1,000
MWofinterruptiblecustomerloadwasshedthroughouttheinterconnected
systemsbydevicesthatautomaticallyoperatedtoprotectvariouspartsofthe
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system(asdeterminedbytheTPLandTOPStandards).Thisdemonstrateshow
thesuiteofstandardsdefinedbyNERCworktogethertoefficientlyprotectthe
systemandminimizecustomerinterruptions.

CONCLUSIONS

VIII.

Thereareimportantconclusionsthatcanbedrawnfromthisworkandthe
mathematicalguaranteesthatitprovides:

o TheDisturbanceControlStandard(DCS)ascurrentlyconfiguredonlylooksat
ACE,theimbalancecontributionofasingleBA,anddoesnotincludeaspecific
frequencyerrorcomponentthatindicatestheBA’scontributionrelativetothe
conditionoftheinterconnectiontowhichtheBAisconnected.

o AstheDCSmeasuredoesnothaveaspecificfrequencycomponent,compliance
toDCSattimesconflictswiththeoverallgoaloftargetingoperationwithin
predefinedInterconnectionfrequencylimits.Forexample,DCSrecoveryinitiated
fromaboveScheduledFrequencyhasadetrimentalimpactonInterconnection
frequency.

o ThefocusonACEaloneisinsufficienttocontrolfrequencyonamultipleBA
Interconnection.ThecorrelationoftheACEsamongtheBAsonthe
Interconnectionwillaffectthequalityoffrequencycontrolindependentofhow
anyindividualACEiscontrolled.

o AdequatecontrolofInterconnectionfrequencyrequirestheuseofbothACE
(individualBAbalancingerror)andfrequencydeviation.

o AdequatecontrolofreliabilityriskonanInterconnectionrequirestheuseof
ACE,frequencydeviationandavailablefrequencyresponse.

o BAALaddressesalleventsimpactingInterconnectionfrequency,bothaboveand
belowscheduledfrequency.

BAALaddressesalloftheaboveissuesinitstimedomainwithoutrequiringresponsetoor
measurementofeventsthatfailtoraisereliabilityconcerns.Forthesereasons,theproposed
applicabilityofBALͲ002isareasonableandtechnicallyͲjustifiedapproachthataddressesthe
seamwithEOPͲ002.

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Table of Contents


Introduction .................................................................................................................................... 3
RationalebyRequirement .............................................................................................................. 7
Requirement1 ................................................................................................................................ 7
Requirement2 .............................................................................................................................. 15


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Introduction
TherevisiontoNERCPolicyStandardsin1996createdaDisturbanceControlStandard(DCS).It
replacedB1[(AreaControlError(ACE)mustreturntozerowithin10minutesfollowinga
disturbance)]andB2(ACEmuststarttoreturntozeroin1minutefollowingadisturbance)with
astandardthatstates:ACEmustreturntoeitherzeroorapreͲdisturbancevalueofACEwithin
15minutesfollowingareportabledisturbance.BalancingAuthoritieswerearerequiredto
reportalldisturbancesequaltoorgreaterthan80%oftheBalancingAuthority’sMostSevere
SingleContingency(MSSC).

BALͲ002wascreatedtoreplaceportionsofPolicy1.Itmeasurestheabilityofanapplicable
entitytorecoverfromareportableeventwiththedeploymentofreserve.Thereliable
operationoftheinterconnectedpowersystemrequiresthatadequatecapacityandenergybe
availableatalltimestomaintainscheduledfrequencyandavoidlossoffirmloadfollowingloss
oftransmissionorgenerationcontingencies.Thiscapacity(ContingencyReserve)isnecessary
toreplacecapacityandenergylostduetoforcedoutagesofgenerationortransmission
equipment.ThedesignofBALͲ002andPolicy1waspredicatedontheInterconnection
operatingundernormalconditions,andtherequirementsofBALͲ002assuredrecoveryfrom
singlecontingency(NͲ1)events.

ThisdocumentprovidesbackgroundonthedevelopmentandimplementationofBALͲ002Ͳ2Ͳ
ContingencyReserveforRecoveryfromaBalancingContingencyEvent.Thisdocumentexplains
therationaleandconsiderationsfortherequirementsandtheirassociatedcompliance
information.BALͲ002Ͳ2wasdevelopedtofulfilltheNERCBalancingAuthorityControls(Project
2007Ͳ05)StandardAuthorizationRequest(SAR),whichincludestheincorporationoftheFERC
Order693directives.TheoriginalSAR,approvedbytheindustry,presumesthereispresently
sufficientContingencyReserveinalltheNorthAmericanInterconnections.Theunderlyinggoal
oftheSARwastoupdatethestandardtomakethemeasurementprocessmoreobjectiveand
toprovideinformationtotheBalancingAuthorityorReserveSharingGroup,suchthatthe
partieswouldbetterunderstandtheuseofContingencyReservetobalanceresourcesand
demandfollowingaReportableBalancingContingencyEvent.

Currently,theexistingBALͲ002Ͳ1standardcontainsRequirementsspecifictoaReserveSharing
Groupwhichthedraftingteambelievesarecommercialinnatureandisacontractual
arrangementbetweenthereservesharinggroupparties.BALͲ002Ͳ2isintendedtomeasurethe
successfuldeploymentofcontingencyreservebyresponsibleentities.Relationshipsbetween
theentitiesshouldnotbepartoftheperformancerequirements,butleftuptoacommercial
transaction.
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Clarityandspecificsareprovidedwithseveralnewdefinitions.Additionally,theBALͲ002Ͳ2
eliminatesanyquestionaboutwhoistheapplicableentityandassuresthattheapplicable
entityisheldresponsiblefortheperformancerequirement.Thedraftingteam’sgoalwasto
haveBALͲ002Ͳ2besolelyaperformancestandard.TheprimaryobjectiveofBALͲ002Ͳ2isto
ensurethattheapplicableentityispreparedtobalanceresourcesanddemandandtoreturnits
ACEtodefinedvalues(subjecttoapplicablelimits)followingaReportableBalancing
ContingencyEvent.

Asproposed,thisstandardisnotintendedtoaddresseventsgreaterthanaResponsibleEntity’s
MostSevereSingleContingency.TheselargemultiͲunitevents,althoughunlikely,dooccur.
ManyinteractionsoccurduringtheseeventsandBalancingAuthoritiesandReserveSharing
Groupsmustreacttotheseevents.However,requiringarecoveryofACEwithinaspecifictime
periodismuchtoosimpleofamethodologytoadequatelyaddressalloftheseinteractions.
ThesuiteofNERCStandardworktogethertoensurethattheInterconnectionsareoperatedin
asafeandreliablemanner.Itisnotjustonestandard,ratheritisthecombinationoftheBALͲ
001Ͳ2standard,(inwhichR2requiresoperationwithinanACEbandwidthbasedon
interconnectionfrequency),TOPͲ007,andEOPͲ002,whichcollectivelyaddressissueswhen
largeeventsoccur.
x

TheBalancingAuthorityACELimit(BAAL)inR2ofBALͲ001Ͳ2looksatInterconnection
frequencytoprovidetheBAarangeinwhichtheBAshouldstrivetooperateaswellas
a30ͲminuteperiodtoaddressinstanceswhentheBAisoutsideofthatrange.Ifan
eventlargerthantheBA’sMSSCoccurs,theBAALwilllikelychangetoamuchtighter
controllimitbasedonthechangeininterconnectionfrequency.The30Ͳminutelimit
undertheBAALwillallowstheBA(anditsRC)timetoquicklyevaluatethebestcourse
ofactionandthenreactinareasonablemanner.BAALalsoensurestheResponsible
Entitybalancesresourcesanddemandwhenforeventsoccuroflessmagnitudethana
ReportableBalancingContingency.InadditionR1ofBALͲ001Ͳ2willrequirestheBAto
respondtoassureControlPerformanceStandard1(CPS1)ismet.Thismayrequire
prompttheBAtorespondinsomecircumstancesinlessthan10minutes.

x

TheTOPͲ007standardaddressestransmissionlineloading.MembersoftheBALͲ002Ͳ2
draftingteamareawareofinstances(typicallyNͲ2orless)thatcouldcausetransmission
overloadsifcertainunits(typicallyNͲ1Ͳ1orgreater)werelostandreservesresponded.

x

UnderEOPͲ002,iftheBAdoesnotbelievethatitcanmeetcertainparameters,different
rulesareimplemented.

Becauseofthepotentialforsignificantunintendedconsequencesthatcouldoccurundera
requirementtoactivateallreserves,thedraftingteamrecommendstotheindustrythatthe
revisedBALͲ002Ͳ2onlyaddresseventswhichareplannedfor(NͲ1)andnotanylossof
resource(s)thatwouldexceedMSSC.Therefore,thedefinitionsandRrequirementsunderBALͲ
002Ͳ2excludeeventsgreaterthantheMSSC.ThisprovidesclarityofRequirements,supports
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reliableoperationoftheBulkElectricSystemandallowsotherstandardstoaddresseventsof
greatermagnitudeandcomplexity.

WithinNERC’sStateofReliabilityReport,ALR2Ͳ5“DisturbanceControlEventsGreaterThanthe
MostSevereSingleContingency”hasbeentrackedandreportedsince2006.Fortheperiod
2006to2011therehavebeen90disturbanceeventsthatexceededtheMSSC,withthehighest
inanygivenyearbeing24events.WhenEevaluationngofthedataillustrates,eventsgreater
thanMSSCoccurveryinfrequently,andthedraftingteambelievestheirexclusionwillnothave
anyadverseimpactonreliability.

ThemetricreportsthenumberofDCSeventsgreaterthanMSSC,withoutregardlessoftothe
sizeofaBalancingAuthorityorRSGandwithoutrespecttoofthenumberofreportingentities
withinaRegionalEntity.AsmallBalancingAuthorityorRSGmayhavearelativelysmallMSSC.
Assuch,ahighnumberofDCSeventsgreaterthanMSSCmaynotindicateareliabilityproblem
forthereportingRegionalEntity,butmayindicateanissuefortherespectiveBalancing
AuthorityorRSG.Inaddition,eventsgreaterthanMSSCmaynotcauseareliabilityissuefora
BA,RSGorRegionalEntityiftheyhavethathasmorestringentstandardswhichrequire
contingencyreservegreaterthanMSSC.



Background

ThissectiondiscussesthenewdefinitionsassociatedwithBALͲ002Ͳ2.Reliablybalancingan
Interconnectionrequiresfrequencymanagementandallofitsaspects.Inputstofrequency
managementincludeTieͲLineBiasControl,AreaControlError(ACE),andthevarious
RequirementsinNERCResourceandDemandBalancingStandards,specificallyBALͲ001Ͳ2Real
PowerBalancingControlPerformanceandBALͲ003Ͳ1FrequencyResponseandFrequencyBias
Setting.
BalancingContingencyEvent
ThepurposeofBALͲ002Ͳ2appliesduringtherealͲtimeoperationsandistoensurethe
BalancingAuthorityorReserveSharingGroupbalanceresourcesanddemandbyreturningits
AreaControlErrortodefinedvaluesfollowingaReportableBalancingContingencyEvent.
ThedraftingteamincludedaspecificdefinitionforaBalancingContingencyEventtoeliminate
anyconfusionandambiguity.ThepriorversionofBALͲ002wasbroadandcouldbeinterpreted
invariouswaysmannersleavingtheabilitytomeasurecomplianceuptointheeyeofthe
beholder.ByIincludingthespecificdefinition,itallowstheResponsibleEntitytofully
understandhowtoperformandmeetcompliance.Also,FERCOrder693(atP355)directed
entitiestoincludeaRequirementthatmeasuresresponseforanyeventorcontingencythat
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causesafrequencydeviation.Bydevelopingaspecificdefinitionthatdepictstheevents
causinganunexpectedchangetotheResponsibleEntity’sACE,thenecessaryresponse
requirementsassurestheintentoftheFERC’srequirementismet.
MostSevereSingleContingency
TheMostSevereSingleContingency(MSSC)termhasbeenwidelyusedwithintheindustry;
however,ithasneverbeendefined.Inordertoeliminateawiderangeofdefinitions,the
draftingteamhasincludedaspecificdefinitiondesignedtofulfilltheneedsofthestandard.In
addition,inordertomeetFERCOrderNo.693(atP356),todevelopacontinentͲwide
contingencyreservepolicy,itwasnecessarytoestablishadefinitionofforMSSC.
WhenanentitydeterminesitsMSSC,thereviewneedstoincludethelargestlossofresource
thatmightoccurforeithergenerationortransmissionloss.Ifthelossoftransmissioncauses
thelossofgenerationandload,thesizeofthateventwouldbethenetchange.Sincethesizeof
aneventwherebothloadandgenerationarelostduetothelossofthetransmissionwouldbe
lessthanjustthelossofthegenerator,itthiseventisunlikelyimpossibleforthiseventtobethe
entity’sMSSC.Also,noteherethatthedraftingteamremovedthepreviousrequirementto
reviewtheMSSCatleastannually.AnentityshouldknowwhatitsMSSCisatalltimes.
Therefore,anannualreviewisnolongerrequired
ContingencyReserve
Mostsystemoperatorsgenerallyhaveagoodunderstandingoftheneedtobalanceresources
anddemandandreturntheirAreaControlErrortodefinedvaluesfollowingaReportable
BalancingContingencyEvent.However,theexistingContingencyReservedefinitionisprimarily
focusedprimarilyongenerationandnotsufficientlyonDemandͲSideManagement(DSM).In
ordertomeetFERCOrderNo.693(atP356)toincludearequirementthatexplicitlyallows
DSMtobeusedasaresourceforcontingencyreserve,thedraftingteamelectedtoexpandthe
definitionofContingencyReservetoexplicitlyincludecapacityassociatedwithDSM.
Additionally,conflictexistedbetweenBALͲ002andEOPͲ002astowhenanentitycoulddeploy
itscontingencyreserve.EOPͲ002alsoappliesduringtherealͲtimeoperationstimehorizonand
addressescapacityandenergyemergencies.Giventhatanentityand/oreventcantransition
suddenlyfromnormaloperations(BALͲ002)intoemergencyoperations(EOPͲ002),this
transitionalseammustbeexplicitlyaddressedinordertoprovideclaritytoresponsibleentities
regardingtheactionstobetaken.
ToeliminatethepossibleconflictandtoassureBALͲ002andEOPͲ002worktogetherand
compleimenteachother,thedraftingteamclarifiedtheexistingdefinitionofContingency
Reserve.TheconflictarisessincetheactionsrequiredbyEnergyDeficientEntitiesbefore
declaringeitheranEnergyEmergencyAlert2oranEnergyEmergencyAlert3requiresinclude
deploymentofallOperatingReservewhichincludesContingencyReserve.AnEnergyDeficient
EntitymayneedtodeclareeitheranEnergyEmergencyAlert2oranEnergyEmergencyAlert3,
withoutincurringaBalancingContingencyEvent.WithoutincurringaBalancingContingency
Event,aResponsibleEntitycannotutilizeitsContingencyReservetotheextentitdropsbelow
MSSCwithoutviolatingtheNERCStandardBALͲ002Ͳ2.Toresolvethisconflict,thedrafting
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teamelectedtoallowtheResponsibleEntitytobeexemptfromR2ifinanEnergyEmergency
AlertLevelunderwhichtheResponsibleEntitynolongerhasrequiredContingencyReserves
availableprovidedthathavebeenactivatedorwheretheResponsibleEntityhasmade
preparationsforinterruptionofFirmLoadtoreplacetheshortfallofContingencyReserveto
avoidtheuncontrolledfailureofcomponentsorcascadingoutagesoftheInterconnection.is
unabletomeetContingencyReserverequirementsduetosystemconditions.
Also,toassurethesystemoperatorhasthenecessaryflexibilitytoaddressthetransitionfrom
normaloperations(BALͲ002)intoemergencyoperations(EOP)thedraftingteamelectedto
allowtheResponsibleentitytobeexemptfromR2duringoneormoreofthefollowingperiods
whentheResponsibleEntityis:
x

usingitsContingencyReserveforContingenciesthatarenotBalancing
ContingencyEvents;

x

respondingtoanOperatingInstructionrequiringtheuseofContingencyReserve;

x

resolvingtheexceedanceofaSystemOperatingLimitorIROLthatrequiresthe
useofContingencyReserve;and,

x

inaContingencyEventRecoveryPeriodoritssubsequentContingencyReserve
RestorationPeriod.

ForadditionaltechnicaljustificationforexemptingperiodsfromR2tofacilitateapplicabilityof
transitioningsuddenlyfromnormaloperationsintoemergencyoperationspleasereferto
Attachment3.
touseitsContingencyReservewhileinadeclaredEnergyEmergencyAlert2orEnergy
EmergencyAlert3.
ReserveSharingGroupReportingACE
Thedraftingteamelectedtoincludethisdefinitiontoprovideclarityformeasurementof
complianceoffortheappropriateResponsibleEntity.Additionally,thisdefinitionisnecessary
sincethedraftingteamhaseliminatedR5.1andR5.2thatareinfromtheexistingstandard.
R5.1andR5.2mixaredefinitionsmixedwithperformance.Thedraftingteamhasincludedall
theperformancerequirementsintheproposedstandardsR1andR2,andthereforehasmust
addedthedefinitionoftheReserveSharingGroupReportingACE.
OtherDefinitions
Otherdefinitionshavebeenaddedormodifiedtoassureclarificationwithinthestandardand
requirements.


RationalebyRequirement


Requirement1
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TheResponsibleEntityexperiencingaReportableBalancingContingencyEventshall,within
theContingencyEventRecoveryPeriod,demonstraterecoverybyreturningits
ReportingACEtoatleasttherecoveryvalueof:

o Zero(ifitsPreͲReportingContingencyEventACEValuewaspositiveorequal
tozero);however,duringtheContingencyEventRecoveryPeriod,any
BalancingContingencyEventthatoccursshallreducetherequiredrecovery:
(i)beginningatthetimeof,and(ii)bythemagnitudeof,eachindividual
BalancingContingencyEvent,
or
o ItsPreͲReportingContingencyEventACEValue,(ifitsPreͲReporting
ContingencyEventACEwasnegative):however,duringtheContingency
EventRecoveryPeriod,anyBalancingContingencyEventthatoccursshall
reducetherequiredrecovery:(i)beginningatthetimeof,and(ii)bythe
magnitudeof,eachindividualBalancingContingencyEvent.
1.1

AllReportableBalancingContingencyEventswillbedocumentedusingCRForm
1.

1.2. AResponsibleEntityisnotsubjecttocompliancewithRequirementR1whenitis
experiencingaReliabilityCoordinatorapprovedEnergyEmergencyAlertLevel
underwhichContingencyReserveshavebeenactivated.
1.3RequirementR1(initsentirety)doesnotapply:
x

(i)whentheResponsibleEntityexperiencesaBalancingContingencyEventthat
exceedsitsMostSevereSingleContingency,or

x

(ii)aftermultipleBalancingContingencyEventsforwhichthecombined
magnitudeexceedstheResponsibleEntity’sMostSevereSingleContingencyfor
thoseeventsthatoccurwithinthat105minuteperiod..



BackgroundandRationale
RequirementR1reflectstheoperatingprinciplesfirstestablishedbyNERCPolicy1.Its
objectiveistoassuretheResponsibleEntitybalancesresourcesanddemandandreturnsits
ReportableAreaControlError(ACE)todefinedvalues(subjecttoapplicablelimits)followinga
ReportableBalancingContingencyEvent.ItrequirestheResponsibleEntitytorecoverfrom
eventsthatwouldbelessthanorequaltotheResponsibleEntity’sMSSC.Itestablishesa
ceilingfortheamountofContingencyReserveandrecoveryandrestorationtimeframesthe
ResponsibleEntitymustdemonstrateinacomplianceevaluation.Itisintendedtoeliminate
theambiguitiesandquestionsassociatedwiththeexistingstandard.Inaddition,itallows
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ResponsibleEntitiestohaveaclearwaytodemonstratecomplianceandsupportthe
InterconnectiontothefullextentofitsMSSC.
Byincludingnewdefinitions,andmodifyingexistingdefinitions,andtheaboveR1,thedrafting
teambelievesithassuccessfullyfulfilledtherequirementsofFERCOrderNo.693(atP356)to
includearequirementthatexplicitlyallowsDSMtobeusedasaresourceforContingency
Reserve.Italsorecognizesthatthelossoftransmissionaswellasgenerationmayrequirethe
deploymentofContingencyReserve.
Additionally,R1isdesignedtoassuretheapplicableentityusesreservetocoveraReportable
BalancingContingencyEventorthecombinationofanypreviousBalancingContingencyEvents
thathaveoccurredwithinthespecifiedperiod,toaddresstheOrder’sconcernthatthe
applicableentityisrespondingtoeventsandperformanceismeasured.TheReportable
BalancingContingencyEventdefinition,alongwithR1allowsformeasurementofperformance.
ThedraftingteamhasincludedAttachment2illustratinganexampleofthecalculationfor
RequirementR1.
Inaddition,thestandarddraftingteam(SDT)throughR1Pparts1.2andR1.3hasclearly
identifiedwhenR1isnotapplicable.ByincludingR1Ppart1.2,theproposedstandard
eliminatestheexistingconflictwiththeEOPStandardsandfurtheraddressestheoutstanding
interpretation.ByclearlystatingwhenR1isnotapplicableordoesnotapply,iteliminatesany
auditorinterpretationandallowstheResponsibleEntitytoperformthefunctioninareliable
manner.AfundamentalgoaloftheSDTistoassuretheResponsibleEntityhasenough
flexibilitytomaintainservicetoloadwhilemanagingreliability.Also,theSDT’sintentisto
eliminateanypotentialoverlaporconflictwithanyotherNERCReliabilityStandardtoeliminate
duplicativereporting,andotherissues.
ThedraftingteamuseddatasuppliedbytheConsortiumforElectricReliabilityTechnology
Solutions(CERTS)tohelpdeterminealleventsthathaveanimpactonfrequency.Datathat
wascompiledbyCERTStoprovideinformationonmeasuredfrequencyeventsispresentedin
Attachment1.Analyzingthedata,onecoulddemonstraterevealseventsof100MWorgreater
wouldcaptureallfrequencyeventsforallinterconnections.However,ata100MWreporting
threshold,thenumberofeventsreportedwouldsignificantlyincreasewithnoreliabilitygain
since100MWismorereflectiveoftheoutlyingevents,especiallyonlargerinterconnections.
ThegoalofthedraftingteamwastodesignacontinentͲwidestandardtocapturethemajority
oftheeventsthatimpactfrequency.Afterreviewingthedataandindustrycomments,theSDT
electedtoestablishreportingthresholdminimumsforeachrespectiveInterconnection.This
assurestherequirementsoftheFERCOrderNo.693aremet.Thereportablethresholdwas
selectedasthelesserof80%oftheapplicableentity’s(s)MostSevereSingleContingencyorthe
followingvaluesforeachrespectiveInterconnection:
x
x
x
x

EasternInterconnection–900MW
WesternInterconnection–500MW
ERCOT–800MW
Quebec–500MW

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Additionally,thedraftingteamonlyusedonlylossofresourcethepositiveeventsforpurposes
ofdeterminingtheabovethresholds.
ViolationSeverityLevels
IntheViolationSeverityLevelsforRequirementR1,theimpactoftheResponsibleEntity
recoveringfromaReportableBalancingContingencyEventdependsonthepercentageof
desiredrecoveryachievedamountofitsContingencyReserveavailableandwhetherdoesit
hasvesufficientresponse.TheVSLtakesthesefactorsintoaccount.
ComplianceCalculation
ItisimportanttonotethatR1adjuststherequiredrecoveryvalueofReportingACEforany
otherBalancingContingencyEventsthatoccurduringtheContingencyEventRecoveryPeriod.
However,todeterminecompliancewithR1,themeasuredcontingencyreserveresponse
(insteadoftherequiredrecoveryvalueofReportingACE)isadjustedforanyotherBalancing
ContingencyEventsthatoccurduringtheContingencyEventRecoveryPeriod.Bothmethodsof
adjustmentaremathematicallyequivalent.AccordinglyTodeterminecompliancewithR1,the
measuredcontingencyreserveresponseiscomputedandcomparedwiththeMWlostas
follows(assumingallresourcelossvalues,i.e.BalancingContingencyEvents,arepositive)to
measurecompliance1:
• Themeasuredcontingencyreserveresponseisequaltooneofthefollowing:
o IfthePreͲReportableContingencyEventACEValueisgreaterthanorequal
tozero,thenthemeasuredcontingencyreserveresponseequals(a)the
megawattvalueoftheReportableBalancingContingencyEventplus(b)the
mostpositiveACEvaluewithinitsContingencyEventRecoveryPeriod(and
followingtheoccurrenceofthelastsubsequentevent,ifany)plus(c)the
sumofthemegawattlossesofthesubsequentBalancingContingencyEvents
occurringwithintheContingencyEventRecoveryPeriodoftheReportable
BalancingContingencyEvent.
o IfthePreͲReportableContingencyEventACEValueislessthanzero,thenthe
measuredcontingencyreserveresponseequals(a)themegawattvalueof
theReportableBalancingContingencyEventplus(b)themostpositiveACE
valuewithinitsContingencyEventRecoveryPeriod(andfollowingthe
occurrenceofthelastsubsequentevent,ifany)plus(c)thesumofthe
1

Inadjustingfortheadverseimpactofrapidlysucceeding(i.e.“near”)EventsonaResponsibleEntity’sRecovery

fromanEvent,theSDTthoughtitmoreprudenttoadjustforfuturenearEventsratherthanforpastnearEvents
becausethefutureEventsplaceanaddedburdenonperformance,whileadjustingforthepastEventsinstead
lowerstheperformancerequirement.ToadjustforbothfutureandpastEventsamountstodoubledealing
becauseanEventissubsequenttoapriornearEvent,andbothEventswouldbeservingtorelieveRecoveryfrom
eachother.TheSDTallowedonlyfortheextremecaseofexemptingfromrecoverypriornearEventsthat
combinedexceedMSSC.

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megawattlossesofsubsequentBalancingContingencyEventsoccurring
withintheContingencyEventRecoveryPeriodoftheReportableBalancing
ContingencyEvent,minus(d)thePreͲReportableContingencyEventACE
Value.
• ComplianceiscomputedasfollowsonCRForm1inordertodocumentall
BalancingContingencyEventsusedincompliancedetermination:
ƒ

Ifthemeasuredcontingencyreserveresponseisgreaterthanor
equaltothemegawattslost,thentheReportableBalancing
ContingencyEventComplianceequals100percent.

ƒ

Ifthemeasuredcontingencyreserveresponseislessthanorequalto
zero,thentheReportableBalancingContingencyEventCompliance
equals0percent.

ƒ

Ifthemeasuredcontingencyreserveresponseislessthanthe
megawattslostbutgreaterthanzero,thentheReportableBalancing
ContingencyEventComplianceequals100%*(1–((megawattslost–
measuredcontingencyreserveresponse)/megawattslost)).


Theabovecomputationscanbeexpressedmathematicallyinthefollowing5sequentialsteps,
labeledas[1Ͳ5],where:
ACE_BEST–mostpositiveACEduringtheContingencyEventRecoveryPeriodoccurringafter
thelastsubsequentevent,ifany(MW)
ACE_PREͲPreͲReportableContingencyEventACEValue(MW)
COMPLIANCEͲReportableBalancingContingencyEventCompliancepercentage(0Ͳ100%)
MEAS_CR_RESPͲmeasuredcontingencyreserveresponsefortheReportableBalancing
ContingencyEvent(MW)
MSSC–MostSevereSingleContingency(MW)
MW_LOSTͲmegawattlossoftheReportableBalancingContingencyEvent(MW)
SUM_SUBSQͲsumofthemegawattlossesofsubsequentBalancingContingencyEvents
occurringwithintheContingencyEventRecoveryPeriodoftheReportableBalancing
ContingencyEvent(MW)

IfACE_PREisgreaterthanorequalto0,then
MEAS_CR_RESP=MW_LOST+ACE_BEST+SUM_SUBSQ[1]

IfACE_PREislessthan0,then
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MEAS_CR_RESP=MW_LOST+ACE_BEST+SUM_SUBSQ–ACE_PRE[2]

IfMEAS_CR_RESPisgreaterthanorequaltoMW_LOST,then
COMPLIANCE=100[3]

IfMEAS_CR_RESPislessthanorequalto0,then
COMPLIANCE=0[4]

IfMEAS_CR_RESPisgreaterthan0,and,MEAS_CR_RESPislessthanMW_LOST,then
COMPLIANCE=100*(1–((MW_LOST–MEAS_CR_RESP)/MW_LOST))[5]


TheDecisionTreeflowdiagramforDCSbelow,providesavisualizationofthelogicflowfora
ReportableBalancingContingencyEvent.Itincludesdecisionblocksforinitialevent
determination,subsequenteventdetermination,andcheckingforMSSCexceedance which
shouldassisttheResponsibleEntitywithEventRecoveryandanalysis.


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BAAL and
IROL

Resource Loss
> Reporting
Threshold

DCS Real
Time


DCS Off
Line
Reporting

N

Sudden?

Y

Start 15
Minute
Recovery



Subsequent
Events?

Y



N

DecisionTreeforDCS

Make Best
Efforts on
Recovery

> MSSC

Adjust
Calculations

Y

13

N

If IROL or
BAAL
Exceeded, Begin
30 Min Recover

Complete
Form

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DisturbanceControlPerformanceͲContingencyReserveforRecoveryFromaBalancing
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Requirement2
R2.TheResponsibleEntityshallmaintainContingencyReserve,averagedovereachClock
Hour,greaterthanorequaltoitsaverageClockHourMostSevereSingle
Contingency,exceptduringoneormoreofthefollowingperiodswhenthe
ResponsibleEntityis:
2.1 usingitsContingencyReserve,foraperiodnottoexceed90minutes,
tomitigatethereliabilityconcernsassociatedwithContingenciesthat
arenotBalancingContingencyEvents;and/or
2.2 usingitsContingencyReserve,foraperiodnottoexceed90minutes,
torespondtoanOperatingInstructionrequiringtheuseof
ContingencyReserve;and/or
2.3 usingitsContingencyReserveforaperiodnottoexceed90minutes,
toresolvetheexceedanceofaSystemOperatingLimit(SOL)or
InterconnectionReliabilityOperationLimit(IROL)thatrequiresthe
useofContingencyReserve;and/or
2.4 inaContingencyReserveRestorationPeriod;and/or
2.5 inaContingencyEventRecoveryPeriod;and/or
2.6 inanEnergyEmergencyAlertLevelunderwhichtheResponsible
EntitynolongerhasrequiredContingencyReserveavailableprovided
thattheResponsibleEntityhasmadepreparationsforinterruptionof
FirmLoadtoreplacetheshortfallofContingencyReservetoavoidthe
uncontrolledfailureofcomponentsorcascadingoutagesofthe
Interconnection.Forthisexemptiontoapply,thepreparationsmust
beinitiatedwithin5minutesfromthetimethattheEnergy
EmergencyAlertLevelisdeclared.
usingitsContingencyReserveforContingenciesthatarenotBalancing
ContingencyEvents.
respondingtoanOperatingInstructionrequiringtheuseofContingencyReserve;
resolvingtheexceedanceofaSystemOperatingLimitorIROLthatrequiresthe
useofContingencyReserve;and,
inaContingencyEventRecoveryPeriodoritssubsequentContingencyReserve
RestorationPeriod.

AnytimeanentitydeploysContingencyReserveforanyoftheabovereasonsand
itsremainingContingencyReserveisbelowtherequiredminimumlevel,theentity
willhaveaperiodnottoexceed90minutesfromthetimetheamountof
ContingencyReservesdropsbelowthelevelrequiredinthisR2torestoreits
reservestomeetR2.
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inanEnergyEmergencyAlertLevelunderwhichtheResponsibleEntitynolonger
hasrequiredContingencyReserveavailableprovidedthattheResponsibleEntity
hasmadepreparationsforinterruptionofFirmLoadtoreplacetheshortfallof
ContingencyReservetoavoidtheuncontrolledfailureofcomponentsorcascading
outagesoftheInterconnection.
TheResponsibleEntityshallmaintainContingencyReserve,averagedovereachClockHour,
greaterthanorequaltoitsaverageClockHourMostSevereSingleContingency,
exceptduringperiodswhentheResponsibleEntityisin:
arestorationperiodbecauseithasuseditsContingencyReserveforContingenciesthatare
notBalancingContingencyEvents.Thisrequiredrestorationbeginswhenthe
ResponsibleEntity’sContingencyReservefallsbelowitsMSSCandmustnotexceed
90minutes;and/or
aContingencyEventRecoveryPeriodoritssubsequentContingencyReserveRestoration
Period;and/or
anEnergyEmergencyAlertLevelunderwhichContingencyReserveshavebeenactivated.
BackgroundandRationale
R2establishesauniformcontinentͲwidecontingencyreserverequirement.R2establishesa
requirementthatcontingencyreservebeatleastequaltotheapplicableentity’sMostSevere
SingleContingency.ByincludingadefinitionofMostSevereSingleContingencyandR2,a
consistentuniformcontinentͲwidecontingencyreserverequirementhasbeenestablished.Its
goalistoassurethattheResponsibleEntitywillhavesufficientcontingencyreservethatcanbe
deployedtomeetR1.
FERCOrder693(atP356)directedBALͲ002tobedevelopedasacontinentͲwidecontingency
reservepolicy.R2fulfillstherequirementassociatedwiththerequiredamountofcontingency
reserveaResponsibleEntitymusthaveavailabletorespondtoaReportableBalancing
ContingencyEvent.WithinFERCOrder693(atP336)theCommissionnotedthatthe
appropriatemixofoperatingreserve,spinningreserveandnonͲspinningreserveshouldbe
addressed.However,theOrderpredatedtheapprovalofthenewBALͲ003,whichaddresses
frequencyresponsivereserveandtheamountoffrequencyresponseobligation.Withthe
developmentofBALͲ003,andtheassociatedreliabilityperformancerequirement,theSDT
believesthat,withR2ofBALͲ002andtheapprovalofBALͲ003,theCommission’sgoalsofa
continentͲwidecontingencyreservespolicyismet.ThesuitesofBALstandards(BALͲ001,BALͲ
002,andBALͲ003)areallperformanceͲbased.Withthesuiteofstandardsandthespecific
requirementswithineachrespectivestandard,acontinentͲwidecontingencypolicyis
established.
IntheViolationSeverityLevelsforRequirementR1,theimpactoftheResponsibleEntity
recoveringfromaReportableBalancingContingencyEventdependsontheamountofits
ContingencyReserveavailableandwhetherdoesithashavesufficientresponse.Additionally,
thedraftingteamunderstandsthattheResponsibleEntity’savailableContingencyReservemay
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varyslightlyfromMSSCatanytime.ThisvariabilityisrecognizedinRequirementR2through
averagingtheavailableContingencyReserveovereachClockHour.
TheidealgoalofmaintaininganamountofContingencyReservetocovertheMostSevere
SingleContingencyatalltimesisnotnecessarilyinthebestinterestofreliability.Itmayhave
theunintendedresultoftyingtheoperators'handsbyremovingtheuseoftheiravailable
contingencyreservefromtheirtoolboxinordertomaintainservicetoloadormanageother
reliabilityissues.ByallowingfortheoccasionaluseofthisminimalamountofContingency
Reserveattheoperators'discretionforothercontingencies,reliabilityisenhanced.TheSDT
craftedtheproposedstandardtoencouragetheoperatorstouse,attheirdiscretionandwithin
thelimitssetforthinthestandard,theiravailablecontingencyreservetobestservereliability
inRrealͲtime.ThelastthingthatanyonedesiresistohaveContingencyReserveheldavailable
andthelightsgooffbecausethestandardwouldpenalizetheoperatorforusingthe
ContingencyReservetomaintainservicetotheload.However,thedraftingteamdidnot
believethattheuseofreservesforotherissuesotherthanaReportableBalancingContingency
Eventshouldbeunbounded.TheSDTlimitedtheuseofContingencyReserveforonlyother
Contingencies,thusboundingtheuseofContingencyReservetoonlytheNͲ1conditions.


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Attachment 1
NERC Interconnections 2009-2013
Frequency Events Loss MW Statistics

For: NERC BARC Standard Drafting Team
Prepared by: CERTS
Date: October 15, 2013

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ContingencyEventStandardBackgroundDocument

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Attachment 2
BAL-002-2 R1 Example

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Requirement1
TheResponsibleEntityexperiencingaReportableBalancingContingencyEventshall,within
theContingencyEventRecoveryPeriod,demonstraterecoverybyreturningits
ReportingACEtoatleasttherecoveryvalueof:[ViolationRiskFactor:Medium][Time
Horizon:RealͲtimeOperations]
o

Zero,(ifitsPreͲReportingContingencyEventACEValuewaspositiveorequal
tozero);however,duringtheContingencyEventRecoveryPeriod,any
BalancingContingencyEventthatoccursshallreducetherequiredrecovery:
(i)beginningatthetimeof,and(ii)bythemagnitudeof,eachindividual
BalancingContingencyEvent,

Or,
o ItsPreͲReportingContingencyEventACEValue,(ifitsPreͲReporting
ContingencyEventACEValuewasnegative);however,duringthe
ContingencyEventRecoveryPeriod,anyBalancingContingencyEventthat
occursshallreducetherequiredrecovery:(i)beginningatthetimeof,and(ii)
bythemagnitudeof,eachindividualBalancingContingencyEvent.
ToillustratetheaboverequirementthefollowingscenarioofthreeBalancingContingency
Events,andcomplianceforeachevent,isprovided.Itisassumedinthisscenariothatthe
reportableeventthresholdis200MW.

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Event 1 Compliance

x
x
x
x

Responsible Entity Pre Reporting Contingency Event ACE Value is 100 MW
Time of the Balancing Contingency Event 12:05
Size of the Balancing Contingency Event 900 MW
Responsible Entity MSSC 2,000 MW

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x

Resulting Responsible Entity’s ACE Value following the Balancing Contingency
Event – negative 800 MW

With no additional Contingency Events, the Responsible Entity must demonstrate recovery of
Event 1 by returning its Reporting ACE to at least the recovery value of zero within the
Contingency Event Recovery Period, or by 12:20.
However, if the Responsible Entity experienced another Contingency Event (Event 2) based
upon the following:
x ACE had recovered to negative 350 – prior to Event 2
x Time of the Contingency Event 12:10
x Size of the Contingency Event 400 MW
x Responsible Entity Reporting ACE Value at 12:10 – negative 750
At the time of Event 2, the Responsible Entity would reduce the value of its required recovery
from the original Balancing Contingency Event 1 by the size of the Contingency Event at 12:10
(Event 2), thus lowering the required recovery value of ACE to negative 400 MW. The
Responsible Entity would demonstrate recovery from Balancing Contingency Event 1, taking
into account Event 2, by returning its Reporting ACE to at least a negative 400 MW by 12:20.
Now if the Responsible Entity experienced an additional Contingency event (Event 3) prior to
12:20 namely:
x ACE had recovered to negative 550 MW – prior to Event 3
x Time of the Contingency Event 12:15
x Size of the Contingency Event 200 MW
x Responsible Entity Reporting ACE Value at 12:15 – negative 750
At the time of Event 3, the Responsible Entity would reduce the value of its required ACE
recovery from the original Balancing Contingency Event 1 by the size of the Contingency Event
at 12:10 (Event 2) and the Contingency Event at 12:15 (Event 3), thus lowering the required
ACE recovery value to negative 600 MW. The Responsible Entity would demonstrate recovery
from Balancing Contingency Event 1, taking into account Events 2 and 3 by returning its
Reporting ACE to at least a negative 600 MW by 12:20.
The Responsible Entity must show compliance for all events in kind that might occur during the
Contingency Event Recovery Period (Event 1). Event 2 and Event 3 from the example above
would demonstrate compliance in a similar fashion as was demonstrated for Event 1 above.
Each would have its own unique Contingency Event Recovery Period as defined by the start of
the respective contingency event (i.e. Event 2’s Contingency Event Recovery Period would
begin at from 12:10 and end at 12:25; Event 3’s Contingency Event Recovery Period would
begin at from 12:15 and end at 12:30). However, tThe Pre-Reporting Contingency required
ACE Value (0 MW) of recovery fromfor Events 1; the required ACE Value (-200 MW) of
Recovery from Event 2 would be the required Value (0 MW) of Recovery from final Event 3)
minus the size of Event 3 (200 MW), while the required ACE Value (-600 MW) of Recovery
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from Event 1 would be the required Value (0MW) of Recovery from final Event 3 minus the size
(600 MW) of the events 2 (400 MW) & 3 (200 MW) subsequent to Event 1.

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The following demonstrates the logic used for compliance with Event 2 (from 12:10 – 12:25,
including Event 3).
Event 2 Compliance

Responsible Entity’s required ACE Value of recovery from Event 2 is 0 MW (the same as it was
from the pre-existing initial Contingency Event 1 prior to any adjustment for Event 2)
x Time of the Balancing Contingency Event 12:10
x Size of the Balancing Contingency Event 400 MW
x Responsible Entity MSSC 2,000 MW
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x

Resulting Responsible Entity’s ACE Value following the Balancing Contingency
Event – negative 750 MW

With no additional Contingency Events, the Responsible Entity must demonstrate recovery from
Event 2 by returning its Reporting ACE to Event 1’s prior, unadjusted Pre-Reporting
Contingency Event ACE value of 0 MW within the Contingency Event Recovery Period, or by
12:25.
However, the Responsible Entity experienced another Contingency Event (Event 3) based upon
the following:
x
x
x
x

ACE had recovered to negative 550 – prior to Event 3
Time of the Contingency Event 12:15
Size of the Contingency Event 200 MW
Responsible Entity Reporting ACE post Contingency Event – negative 750

At the time of Event 3, the Responsible Entity would reduce the value of its required recovery
from the Balancing Contingency Event 2 by the size of Contingency Event 3 at 12:15, thus
lowering the required ACE recovery from Event 2 to negative 200 MW. The Responsible Entity
would demonstrate recovery from both Balancing Contingency Event 1 and Balancing
Contingency Event 2, taking in to account Event 3, by returning its Reporting ACE to at least a
negative 200 MW by 12:30.

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The following demonstrates the logic used for compliance following Event 3 (from 12:15 –
12:30).
Event 3 Compliance

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The Responsible Entity’s required ACE Value of recovery from final Event 3 is 0 MW (the same
as it was from the initial Balancing Contingency Event 1 prior to any subsequent events)
x Time of the Balancing Contingency Event 12: 15
x Size of the Balancing Contingency Event 200 MW
x Responsible Entity MSSC 2,000 MW
Resulting Responsible Entity’s ACE Value following the Balancing Contingency
Event – negative 750 MW
With no additional Contingency Events, the Responsible Entity must demonstrate recovery of
final Event 3 by returning its Reporting ACE to the 0 MW ACE value of 0 MW of recovery from
the initial Event 1 within the Contingency Event Recovery Period, or by 12:30.
Theaboveexamplesillustratetheminimumresponseforcompliance.Actualeventsand
recoverieswilldifferbecauseofmatterssuchas,butnotlimitedto,ContingencyReservebeing
deployeddifferently.

Inordertoillustratetheaboverequirementthefollowingisprovided:
ResponsibleEntityPreͲReportingContingencyEventACEValueis100MW
TimeoftheBalancingContingencyEventͲ12:05
SizeoftheBalancingContingencyEventͲ900MW
ResponsibleEntityMSSCͲ2,000MW
ResultingResponsibleEntity’sACEValuefollowingtheBalancingContingencyEvent–negative
800MW

WithnoadditionalContingencyEvents,theResponsibleEntitymustdemonstraterecoveryby
returningitsReportingACEtoatleasttherecoveryvalueofzerowithintheContingencyEvent
RecoveryPeriod,orby12:20.

However,iftheResponsibleEntityexperiencedanotherContingencyEventbaseduponthe
following:
TimeoftheContingencyEventͲ12:10
SizeoftheContingencyEventͲ400MW
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ResponsibleEntityReportingACEValueat12:10–negative750
TheResponsibleEntitywouldreduceitsrequiredrecoveryvaluefortheBalancingContingency
EventrequiredrecoverybythesizeoftheContingencyEventat12:10,thusresultinginthe
requiredACEbeingreduceby400MWtonegative400MW.TheResponsibleEntitywould
demonstraterecoveryfromtheBalancingContingencyEventbyreturningitsReportingACEto
anegative400MWby12:20.
NowiftheResponsibleEntityexperiencedanadditionalContingencyeventpriorto12:20for
example:
TimeoftheContingencyEventͲ12:15
SizeoftheContingencyEventͲ200MW
ResponsibleEntityReportingACEValueat12:15–negative750
TheResponsibleEntitywouldreduceitsrequiredrecoveryvaluefortheBalancingContingency
EventrequiredrecoverybythesizeoftheContingencyEventat12:15,thusresultinginthe
requiredACErecoverybeingreducedbyanother200MWoftonegative600MW.The
ResponsibleEntitywoulddemonstraterecoveryfromtheBalancingContingencyEventby
returningitsReportingACEtoanegative200MWby12:20.
ThiswouldcontinueonforanyadditionalContingencyEventsthatmightoccurduringthe
ContingencyEventRecoveryPeriod.NotethattheadjustmentstotheReportableACEvalue
requiredforrecoveryaremadeonlyafterthesubsequentBalancingContingencyEventfully
occurs.











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Attachment 3
Technical Justification for Applicability
of BAL-002 During Emergency Alerts

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TechnicalJustificationforApplicabilityofBALͲ002
DuringEnergyEmergencyAlerts

I.

INTRODUCTION


TheBalancingAuthorityReliabilityͲbasedControlsstandarddraftingteam(BARCSDT)has
identifiedaconflictbetweenNERCReliabilityStandardsBALͲ002andEOPͲ002that
unnecessarilyrequiresarbitraryinterruptionofFirmLoad.Inordertoaddressthisissue,the
BARCSDTisrecommendingthatStandardBALͲ002Ͳ2notbeenforceableduringanEnergy
EmergencyAlert(EEA)eventwheretheEEAprocessrequirestheuseofContingencyReserveto
maintainloadservice.2Thisdocumentprovidessupportforthisrecommendationandan
overviewofreliablefrequencymanagementontheNorthAmericanInterconnections.

II.
BACKGROUND

ReliablybalancinganInterconnectionrequiresfrequencymanagementandallofitsaspects.
InputstofrequencymanagementincludeTieͲLineBiasControl,AreaControlError(ACE),and
thevariousRequirementsinNERCResourceandDemandBalancingStandards,specificallyBALͲ
001Ͳ2RealPowerBalancingControlPerformanceandBALͲ003Ͳ1FrequencyResponseand
FrequencyBiasSetting.

ReliabilityStandardBALͲ002appliesduringtherealͲtimeoperationstimehorizonand
addressesthebalancingofresourcesanddemandfollowingadisturbance.ReliabilityStandard
EOPͲ002alsoappliesduringtherealͲtimeoperationstimehorizonandaddressescapacityand
energyemergencies.Giventhatanentityand/oreventcantransitionsuddenlyfromnormal
operationsintoemergencyoperations(EOPͲ002)whereContingencyReservemaintainedunder
BALͲ002maybeutilizedtoserveFirmLoad,thistransitionalseammustbeexplicitlyaddressed
inordertoprovideclaritytoresponsibleentitiesregardingtheactionstobetaken.The
proposedapplicabilityofBALͲ002isdesignedtoaddressthisissue.

III.
LEGACYREQUIREMENTS

TheResourceandDemandBalancing(BAL)standardsincludebothrequirementsthathavea
soundtechnicalbasisandlegacyrequirementsthattheindustryhasusedforyearsbutfailto

2

Theproposedapplicabilitysectionstates:“ApplicabilityisdeterminedonanindividualReportableBalancing
ContingencyEventbasis,buttheResponsibleEntityisnotsubjecttocomplianceduringperiodswhenthe
ResponsibleEntityisinanEnergyEmergencyAlertLevelunderwhichContingencyReserveshavebeenactivated.”
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haveasoundtechnicalbasis.NERCbeganreplacingtheselegacyrequirementswithtechnically
basedrequirementsstartingwiththeControlPerformanceStandard1(CPS1).BothControl
PerformanceStandard2(CPS2)andtheDisturbanceControlStandard(DCS)remaininthe
legacycategory.Thefollowingarespecificconcernsassociatedwiththeserequirements.
o WhenCPS1wasimplementedtoreplaceA1/A2,previousrequirementswere
modifiedsothatCPS1wouldapplyatalltimesincludingthe(disturbance)
periodswhereDCSisapplicable,notjustduringnormaloperations/periods.So
DCSisnottheonlystandardgoverningdisturbanceconditions.
o TheDisturbanceControlStandard(DCS)anditsprecursorB1/B2havebeen
uniqueinrequiringimmediateactionbytheBalancingAuthority(BA),inthis
casetoaddressunexpectedimbalanceswithindefinedlimits.
o DCS,albeitresultsͲbasedinitscurrentform,wasinitiallydesignedtomeasure
theutilizationofContingencyReservetoaddressalossofresourcewithinthe
definedlimits.InitsresultsͲbasedformitassumedthatimplementingsufficient
ContingencyReservesasneededtocomplywiththerecoveryrequirement
wouldbeareasonablyequitableminimumquantityforallBAsparticipatingin
interconnectedoperation.
o DCSisbaseduponACErecoverytothelowerofpreͲdisturbanceACEorzero.A
BalancingAuthoritywhichmightbeunderͲgeneratingpriortoagenerationloss,
couldloseageneratingunitandunderDCSbedeemedcompliantifitreturned
ACEtoitspreͲdisturbancestate,thoughitcouldstillbedepressing
Interconnectionfrequency.
o AsDCSrecoveryfromareportableeventmustoccurwithina15Ͳminuteperiod,
itispossibleforaBalancingAuthority’sACEtoagaingonegativeafterthattime,
withasimilarimpactonInterconnectionfrequency.
o SinceCPS2allowsaBAtobeunaccountableforapproximately74hoursof
operationina31Ͳdaymonth,animbalanceconditionmaypersistandnegatively
impactInterconnectionfrequencyformanyhours3.
o WhenACEismodulatedbyfrequency,“significant”lossesaredefinednotonly
bythesizeoftheeventcausinganACEdeviation,butalsocontingentonthe
deviationofInterconnectionfrequencyfromScheduledFrequency.

IV.
TIEͲLINEBIASFREQUENCYCONTROLANDACE


3

ReliabilityͲBasedControlv3,StandardAuthorizationRequestForm,November7,2007.

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TieͲLineBiasFrequencyControlisimplementedontheNorthAmericanInterconnections
throughtheuseoftheACEEquation.4Ingeneral,ACEisthetermusedtodeterminetheloadͲ
generationimbalancethatisbeingcontributedbyeachBalancingAuthority(BA)onan
Interconnection.ACEisapowerfulindicator,becauseitindicatestheimbalancewithinthe
boundariesofasingleBA,thusdefiningtheSecondaryControlresponsibilitiesforthatBAand,
therefore,thecontrolactionthatwouldreturnACEtozero.ACEincludestheFrequencyBias
Settingterm,whichallowsthePrimaryFrequencyControltobeasharedservicethroughouta
multiͲBAInterconnection,whileassigningtoeachindividualBAthespecificresponsibilitiesof
maintainingitsownSecondaryFrequencyControl.

Insummary,ACEonlyprovidesguidancewithrespecttoSecondaryFrequencyControland
doesnotindicateorprovideanydirectmeasureofPrimaryFrequencyControl,andonlyreflects
theestimatedFrequencyResponseasrepresentedbytheFrequencyBiasSettingterm.NERC
RequirementsandsupportingdocumentationforFrequencyResponse(PrimaryFrequency
Control)areincludedinBALͲ003Ͳ1FrequencyResponseandFrequencyBiasSettingstandard.
MoredetailonTieͲLineBiasFrequencyControlandACEisattached.5

V.
CONTROLPERFORMANCESTANDARD1(CPS1)

PriortothedevelopmentofCPS1,theindustryassumedthat,"Itisimpossible,however,to
usefrequencydeviationtoidentifythespecificcontrolarea(sic,i.e.BA)withtheunderͲor
overͲgenerationcreatingthefrequencydeviation…".3Inthe1990'sthedevelopmentofCPS1
demonstratedthatnotonlywasitpossibletoidentifythespecificBAcreatingthefrequency
deviation,butthatitisalsopossiblenotonlytodeterminetherelativecontributionbyeachBA
tothemagnitudeofthefrequencydeviation6,butalsotodeterminetherelativecontributionof
eachBAtothereliabilityriskcausedbythatdeviation.Inaddition,theCPS1Requirement
providedaguarantee:"IfallBAsonaninterconnectioncompliedwiththeCPS1Requirement,

4

Illian,HowardF.,UnderstandingACE,CPS1andBAAL,PreparedfortheNERCBARCStandardDraftingTeam,
September10,2010rev.August19,2014,Section2,pp.1Ͳ4,foraderivationoftheACEEquationandthe
requirementsforimplementingitthatareincludedinthedefinitionofACEappearingintheNERCGlossary.

5

Illian, Howard F., Frequency Control Performance Measurement and Requirements, Ernest
Orlando Lawrence Berkeley National Laboratory, December 2010, for a discussion of the
history of Frequency Control and Performance Measurement.

6

Illian, Howard F., Understanding ACE, CPS1 and BAAL, Section 2, pp. 5-10 for a derivation
of the CPS1 requirement.

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theRootMeanSquared7valueofthefrequencydeviationforthatInterconnectionwouldbe
lessthantheepsilon18frequencydeviationlimitforthatInterconnection."

CPS1isarollingannualaverageofindividualmeasurementseachaveragedoveroneͲ
minute,andisassessedmonthly.CPS1measuresthecovariancebetweentheACEofaBAand
thefrequencydeviationoftheInterconnectionwhichisequaltothesumoftheACEsofallof
theBAs.CPS1hasthegreatvalueofusingtheInterconnectionfrequencytodeterminethe
degreetowhichACEamongtheBAsonamultipleBAInterconnectionisharmingorhelping
interconnectionfrequency.Sincethefrequencydeviationisameasuredvalue,theACEofaBA
willdirectlyaffectonlytheCPS1oftheBAwiththeACEandnottheCPS1measureofotherBAs.

VI.
BALANCINGAUTHORITYACELIMIT(BAAL)

WhentheBalancingResourcesandDemand(BRD)standarddraftingteamrecognizedthe
needforacontrolmeasureoverashortertimehorizonthaneitherCPS1(annual)orControl
PerformanceStandard29(CPS2,monthly)provided,itbeganlookingforameasurethatwould
allowawindowforcommonimbalanceeventslikeaunittrip,whileprovidingalimitonhow
muchfrequencydeviationshouldbeallowedoverthatshortperiod.Afterconsidering
numerousalternatives,BAALwasselectedastheappropriateshortͲtermmeasure.10,11


7

“Root Mean Squared” means the square root of the mean of the squared errors, so that
positive and negative errors do not offset each other and any shift in the mean is counted
as error.

8

“Epsilon1” is the frequency deviation limit determined for each North American
Interconnection and used by CPS1 to bound the Root Mean Squared frequency deviation.
It is 18 mHz on the Eastern, 22.8 mHz on the Western, 30 mHz on the ERCOT, and 21
mHz on the Quebec Interconnections.

9

Proposed to be replaced by BAAL under BAL-001-2, CPS2 requires the BA to move its ACE
within predefined L10 bounds when it is binding (during only 90% of the ten-minute
periods per month) without regard to whether such action helps or hurts Interconnection
frequency.

10

Illian, Howard F., Meeting the Discrete Event Measure (DEM) Objectives with the
Abnormal Operations Measure (AOM), Prepared for the NERC Balancing Resources and
Demand Standard Drafting Team, March 20, 2004.

11

Illian, Howard F., Setting the Balancing Authority ACE Limit (BAAL) for the NERC
Abnormal Operations Measure (AOM), Prepared for the NERC Balancing Resources and
Demand Standard Drafting Team, March 28, 2004.

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ConsiderableevaluationandFieldTrialshaveshownthatBAAL12isabetterindicatorof
contributionstoreliabilityriskofaninterconnectionthanthemagnitudeofACEalone.This
superiority,likeCPS1’s,derivesfromtheconcurrentuseofbothACEandfrequencyerrorinthe
BAALmeasure.ThusBAALcapturestherelativecontributiontoreliabilitybyalloftheACEson
aninterconnectionandindicateswhereeachBAstandsrelativetoitssecondarycontrol
responsibilitiesandthecurrentstateoftheinterconnectionasindicatedbythefrequencyerror
forbothunderͲandoverͲfrequencyconditions.

VII.
INTERACTIONBETWEENSTANDARDS

Thedraftingteamhasidentifiedasanissuetheexistenceofpointswherethestandardsare
inconflictwitheachother.Thedraftingteamhasattemptedtoaddresstheconflictsidentified,
asfollows:

NERCstandardEOPͲ002requiresaBAtouseallitsreservesduringanEnergyEmergency
Alert2(EEA2)orhigher.ThefollowinglanguageisfoundinEOPͲ002Attachment1ͲEOPͲ002:
2.6.4OperatingReserves.Operatingreservesarebeingutilizedsuchthatthe
EnergyDeficientEntityiscarryingreservesbelowtherequiredminimumor
hasinitiatedemergencyassistancethroughitsoperatingreservesharing
program.

ThecurrentBALͲ002specifiesaminimumlevelreserverequirementatalltimesunlessa
qualifyingeventhasoccurred.ThedraftingteamnotedthatintheEEAprocessanentityis
driventorequestanEEArarelyastheresultofasingleunitloss.Infact,anEEAdeclarationby
theReliabilityCoordinatormightresultfromissuesthatincludenoeventthatwouldqualifyas
aDisturbanceandtheEEAsituationcouldlastlongerthanthereserverecoveryperiodof90
minutes.Forthisreason,thedraftingteamrecommendssignificantchangestothestandardsin
question.

Inadditiontotheidentifiedconflict,otherstandardscanrequiretheactivationof
contingencyreserve.TheseincludeotherBALstandards,IROstandardsandTOPstandards.
Comparedtothosestandards,theBALͲ002standardprovidestheleastdirectmeasureof
reliability.Therefore,anentityshouldneverbeconflictedbetweenapplyingtherequirements
ofBALͲ002andcomplyingwiththeotherstandards.


12

Illian, Howard F., Understanding ACE, CPS1 and BAAL, Prepared for the NERC BARC
Standard Drafting Team, September 10, 2010 rev. August 19, 2014, Section 2, pp. 10, for
a derivation of the BAAL requirement.

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Finally,thereisoneoverarchingprincipalnotreflectedinthediscussionuptothispoint,
namelykeepingthelightsonifpossible.IfthereisarequirementtobringACEbacknomatter
what,thenthatrequirementwillhavetheunintendedconsequenceofsheddingFirmLoad,
especiallyduringanEEA.DuringtheEEAprocess,theexpectationisthataBAwillhavefirm
loadreadytoshedinordertomeetitsreserverequirementunderR2oftheproposedBALͲ002
standard.However,iftheBALͲ002standardalsorequirestheentitytomeetR1duringtheEEA,
entitieswillshedfirmloadtorestoreACEtoitspreͲcontingencylevel,regardlessofthelackof
anyreliabilityissues.Inotherwords,frequencycouldbesettlingatorverynear60Hz,no
transmissionlinesareoverloadedasdeterminedbytheTOPstandards,andtheentityis
operatingwithintheparametersdefinedinBALͲ001,butfirmloadwouldbeinterruptedsimply
tobringtheentity’sACEbacktowhatitwaspriortothelossoftheunit.Sincetheindustryhas
definedreliabilityasfrequencyatornear60Hzandtransmissionlinesoperatingwithintheir
limits,thereisnoreasontointerruptfirmload.

Instead,theBARCSDTisrecommendingthatStandardBALͲ002Ͳ2notbeenforceable
duringanEEAeventwheretheEEAprocessrequirestheuseofContingencyReserveto
maintainloadservice.Instead,theReliabilityCoordinator,TransmissionOperatorsandthe
impactedBalancingAuthoritiesshoulduserealͲtimesituationalawareness,takingintoaccount
issuesaddressedinBALͲ001,BALͲ003,theIROsuiteofstandardsandtheTOPsuiteof
standards,todeterminewhatactionsareappropriatewhenconditionsareabnormal.This
processwouldallowcontinuedloadservicewithoutarbitrarilyrequiringinterruptionoffirm
load.

Thisconcernarisesbecausetheotherstandardslookatspecificreliabilityissuesother
thanjustbalancingbetweenscheduledandactualinterchange.BALͲ001Ͳ2andBALͲ003Ͳ1look
atinterconnectionfrequencytodeterminewhethertheBalancingAuthorityishelpingor
hurtingreliability.DuringanEEAevent,curtailingloadtomoveACEbacktoapreͲeventlevel
couldadverselyaffectfrequency.Iffrequencygoesupfrom60HzwhenaBalancingAuthority
interruptsload,theimpactisdetrimentaltotheinterconnection.UndertheTOPstandards,if
flowsontransmissionlinesarewithinthelimitsspecified,thereisnoneedtoaltertheflowson
thetransmissionsystembyinterruptingload.

Finally,theReliabilityCoordinatorhasawideareaviewoftheelectricsystemas
requiredundertheIROstandards.TheIROstandardsclearlystatetheReliabilityCoordinator’s
responsibilitiesduringtheEEAprocess.IftheReliabilityCoordinatorhasnotidentifieda
reliabilityconcerninitsneartermoperationsevaluation,actionssuchasinterruptionoffirm
loadshouldnotoccursimplytobalanceloadandresourceswithintheBA.Duringabnormal
(emergency)situations,takingsignificantactionswithanarrowviewwillnotbebeneficialfor
Interconnectionreliability.

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EXAMPLES
o Example1
OnanusuallycolddayinFebruary2011,at06:22,aBalancingAuthorityArea
(BAA)experienceda350MWgenerationlosswhena750MWjointownership
unittrippedoffͲline.EarlierinthedaytheBAAoperatorexperiencedlossof
severalgeneratingunitswithatotalcapacityof1050MW,thelatestlossbeing
just38minutespriortothe350MWloss.Whenthe350MWeventoccurred
theBAAoperatorrequestedreserve/emergencyassistance,shed300MWof
customerloadtorestorecontingencyreserve,andrequestedtheRCpostan
EEA3.TheEEA3wasposted.Althoughthefrequencyonlytouched59.91Hz,
averaging59.951Hzinthefirstminuteoftheoutage,wasitreallynecessaryto
cutloadandleavepeopleinthecold,darkofthatmorningtorestore
contingencyreserve?Havingidlegeneration,whentheInterconnectionis
operatingreliably,doesnotwarrantsheddingcustomerload.
o Example2
InJune2012,at17:08,aBAAexperiencedan800MWgenerationloss.TheBA
andthereservesharinggroup(RSG)itparticipatesinwereintheprocessof
replacingthelostgenerationwhen,inthethirteenthminuteoftherecovery
whentherewerenoidentifiedfrequency,voltageorloadingthreatstoreliability,
theBAAwasdirectedbyitsReliabilityCoordinator(RC)toshed120MWof
customerload.AlthoughthecombinedAreaControlError(ACE)oftheRSG
participantswaspositive,theRCfocusedontheACEoftheBAAthatlostthe
generation–whichwasstillnegative–ignoringthefactthattheInterconnection
frequency(59.96Hz)wasabovetheFrequencyTriggerLimit(59.932Hz).The
needlesssheddingofcustomerloadwhensystemreliabilityisnotthreatened
attractedtheattentionofstateregulatorswhowerenothappywiththeaction.
ThisdemonstratesthatfocusingsolelyonaBAA’sACEandnotonthetrue
Interconnectionreliabilityindicatorscancauseactionsthatdonotsupport
reliability.
o Example3
InJune2004,at0741,aseriesofeventsledtoagenerationlossofover4,600
MW.Inspiteoftheeventsize,theInterconnectionfrequencywasarrested
withouttriggeringautomaticunderfrequencyloadshedding,thankstogovernor
action,frequencysensitiveloadanddeploymentofContingencyReserve(as
requiredbyBALͲ002).Sometransmissionelementsexceededtheirlimitsfora
shorttime(aspermittedbytheEOPstandards),And,priortothedisturbance,
thefrequencywasinthenormaloperatingrangeduetoautomaticgeneration
control(AGC)operation(asrequiredbyBALͲ001).Duringtheeventalmost1,000
MWofinterruptiblecustomerloadwasshedthroughouttheinterconnected
systemsbydevicesthatautomaticallyoperatedtoprotectvariouspartsofthe
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system(asdeterminedbytheTPLandTOPStandards).Thisdemonstrateshow
thesuiteofstandardsdefinedbyNERCworktogethertoefficientlyprotectthe
systemandminimizecustomerinterruptions.

CONCLUSIONS

VIII.

Thereareimportantconclusionsthatcanbedrawnfromthisworkandthe
mathematicalguaranteesthatitprovides:

o TheDisturbanceControlStandard(DCS)ascurrentlyconfiguredonlylooksat
ACE,theimbalancecontributionofasingleBA,anddoesnotincludeaspecific
frequencyerrorcomponentthatindicatestheBA’scontributionrelativetothe
conditionoftheinterconnectiontowhichtheBAisconnected.

o AstheDCSmeasuredoesnothaveaspecificfrequencycomponent,compliance
toDCSattimesconflictswiththeoverallgoaloftargetingoperationwithin
predefinedInterconnectionfrequencylimits.Forexample,DCSrecoveryinitiated
fromaboveScheduledFrequencyhasadetrimentalimpactonInterconnection
frequency.

o ThefocusonACEaloneisinsufficienttocontrolfrequencyonamultipleBA
Interconnection.ThecorrelationoftheACEsamongtheBAsonthe
Interconnectionwillaffectthequalityoffrequencycontrolindependentofhow
anyindividualACEiscontrolled.

o AdequatecontrolofInterconnectionfrequencyrequirestheuseofbothACE
(individualBAbalancingerror)andfrequencydeviation.

o AdequatecontrolofreliabilityriskonanInterconnectionrequirestheuseof
ACE,frequencydeviationandavailablefrequencyresponse.

o BAALaddressesalleventsimpactingInterconnectionfrequency,bothaboveand
belowscheduledfrequency.

BAALaddressesalloftheaboveissuesinitstimedomainwithoutrequiringresponseto
ormeasurementofeventsthatfailtoraisereliabilityconcerns.Forthesereasons,the
proposedapplicabilityofBALͲ002isareasonableandtechnicallyͲjustifiedapproachthat
addressestheseamwithEOPͲ002.

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BAL-002-0 R4

BAL-002-0 R3

BAL-002-0 R2

BAL-002-0 R1

Requirement in
Approved Standard

Standard: BAL-002-0 – Disturbance Control Standard
Transitions to the below Requirement in
Description and Change Justification
New Standard or Other Action
This Requirement has been moved into BALThis requirement does not provide for a reliability outcome and if
002-2 Applicability and “Additional
violated would not cause separation, instability or cascading outages.
Compliance Information” sections
This requirement falls under the Paragraph 81 rules. This requirement
This requirement has been removed from
defines a commercial agreement between the BA involved in the RSG.
BAL-002-2
This requirement does not provide for a reliability outcome and if
violated would not cause separation, instability or cascading outages.
This requirement was broken apart. The requirement was defining two
Requirement R1 and R2
separate actions; 1) to require activation of Contingency Reserves, and
2) to require having Contingency Reserves equal to its MSSC.
This Requirement has been moved into BAL002-2 Requirement R1 and into the
A portion of this requirement was defining the timing for recovery from
“Contingency Event Recovery Period” and
an event. This has now been defined and has been proposed to be
“Contingency Reserve Restoration Period”
added to the NERC Glossary of Terms.
definitions.

Transition of BAL-002-0 to BAL-002-2

Project 2010-14.1 Mapping Document

BAL-002-0 R6

BAL-002-0 R5

Requirement in
Approved Standard

This Requirement has been moved into the
BAL-002-2 Requirement R1 and
“Contingency Event Restoration Period”
definition.

2

A portion of this requirement was defining the timing for recovery from
an event. This has now been defined and has been proposed to be
added to the NERC Glossary of Terms.

Standard: BAL-002-0 – Disturbance Control Standard
Transitions to the below Requirement in
Description and Change Justification
New Standard or Other Action
This Requirement has been moved into BALA portion of this requirement was defining how a RSG calculates its
002-2 Requirement R1 and “Reserve Sharing
ACE. This has now been defined and has been proposed to be added
Group Reporting ACE” definition.
to the NERC Glossary of Terms.

Standards Announcement

Project 2010-14.1 Phase 1 of Balancing Authority Reliabilitybased Controls: Reserves - BAL-002-2
Formal Comment Period Open through March 16, 2015
Now Available

A 45-day formal comment period for BAL-002-2 – Contingency Reserve for Recovery from Balancing
Contingency Event is open through 8 p.m. Eastern on Monday, March 16, 2015.
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 Arielle Cunningham. An off-line, unofficial copy of the comment form
is posted on the project page.
Next Steps

An additional ballot and non-binding poll of the associated Violation Risk Factors and Violation
Severity Levels will be conducted March 6 – March 16, 2015.
For more information on the Standards Development Process, please refer to the Standard
Processes Manual.

For more information or assistance, please contact Darrel Richardson, Standards Developer, or at 609-6131848.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Individual or group. (24 Responses)
Name (9 Responses)
Organization (9 Responses)
Group Name (15 Responses)
Lead Contact (15 Responses)
Contact Organization (15 Responses)
IF YOU WISH TO EXPRESS SUPPORT FOR ANOTHER ENTITY'S COMMENTS WITHOUT
ENTERING ANY ADDITIONAL COMMENTS, YOU MAY DO SO HERE. (4 Responses)
Comments (24 Responses)
Question 1 (20 Responses)

Group
MRO-NERC Standards Review Forum
Joe Depoorter
Madison Gas and Electric Company
We commend the drafting team on the improvements made since the last posting. Below are
our concerns and recommendations for improvement. The NSRF is concerned that the
lowering of the threshold to 900 MW for the Reportable Balancing Contingency Event in the
Eastern Interconnection, coupled with the proposed change from quarterly average
performance to individual event performance will increase customer costs and significantly
increase compliance exposure for no difference in reliability risk. Because the interconnection
is over-biased (ACE overstates resource loss) and operators operate conservatively, they will
likely deploy contingency reserves for any loss over 800 MW. Our recommendation is that the
standard uses the lesser of 80% of MSSC or 1000 MW for the Eastern Interconnection. Don’t
Change from Present Quarterly Reporting: We have fundamental concerns with changing the
current quarterly reporting to exception reporting. We can find no directive for this change
which increases compliance exposure and will have unintended consequences in how Reserve
Sharing Groups (RSG) will operate. A failure of a contingency resource to start or start a
minute late can cause performance that has a very low score for that single event, even
though recovery is only a minute late or two late. There are RSGs that mitigate this
compliance risk by deploying reserves for much smaller events, which helps reliability by
quickly recovering from smaller events and replenishing these reserves as well as giving
operators repeated practice in reserve deployment. Since each and every event is individually
sanctionable, these RSGs will quickly change their rules to raise their reportable threshold to
the interconnection minimum. Exception reporting will also eliminate a data source that is
used for NERC’s RAPA group and the State of Reliability Report:
http://www.nerc.com/pa/RAPA/ri/Pages/DCSEvents.aspx, which is another step backward.
We believe there should be a single quarterly report for R1 and R2. The R1 portion would be
very similar to today, to include reporting of events > MSSC (but not part of compliance
evaluation). The quarterly R2 portion of the report should have the number of hours the BA

had reserves < MSSC and an identifier which hours were excludable under 2.1 through 2.6.
The VSLs should be based on the number of hours that reserves were < MSSC and not
ĞdžĐůƵĚĞĚ͗ͻ>Žǁ͗ϮŽƌĨĞǁĞƌŚŽƵƌƐ;ƌĞƉƌĞƐĞŶƚƐϬ͘ϬϵйŽĨƚŚĞŚŽƵƌƐŝŶƚŚĞƋƵĂƌƚĞƌͿͻDĞĚŝƵŵ͗
3-ϱŚŽƵƌƐͻ,ŝŐŚ͗ϲ-ϵŚŽƵƌƐͻ^ĞǀĞƌĞ͗ϭϬŽƌŵŽƌĞŚŽƵƌƐ;ϭϬŚŽƵƌƐƌĞƉƌĞƐĞŶƚƐϬ͘ϱй of the
hours in a month) NERC is trying to move away from zero defect standards. This standard
should be structured to support that concept. The reporting approach need not hard coded in
requirements, but could be compliance section of the standard. We also had comments on a
few specific items in R1. Our suggested wording changes are in [ ]. *** 1.2. A Responsible
Entity is not subject to compliance with Requirement R1 when it is experiencing a Reliability
Coordinator approved Energy Emergency Alert Level under which Contingency Reserves have
been activated [or depleted]. *** Contingencies can happen that take away reserves without
the reserves being activated. And if these contingencies aren’t “sudden”, then it appears
there is no acknowledgment of the reserve loss under the standard. *** (ii) after multiple
Balancing Contingency Events for which the combined [capacity] magnitude exceeds the
Responsible Entity's Most Severe Single Contingency for those events that occur within a 105minute period. *** Contingencies of partially loaded generators remove not only MW from
the BA, but the reserves they had as headroom. It is possible to have multiple contingencies
where the MW loss is < MSSC, but reserves that were lost completely deplete the BA of its
contingency reserves. There should be clarification that the magnitude loss is based on
capacity, not MW loss.
Group
Northeast Power Coordinating Council
Guy Zito
Northeast Power Coordinating Council
There is a possible inconsistency in the terms Balancing Contingency Event, and Reportable
Balancing Contingency Event. Balancing Contingency Event is defined as “Any single event
described in Subsections (A), (B), or (C) below, or any series of such otherwise single events,
with each separated from the next by less than one minute...” Reportable Balancing
Contingency Event is defined as “…(ii) the amount listed below for the applicable
Interconnection, and occurring within a one-minute interval of the initial sudden decline in
ACE…” By its definition, the Balancing Contingency Event, in the extreme, is an unlimited
number of single events, as long as they are separated by less than one minute. Is it intended
for a Reportable Balancing Contingency Event to only encompass what happens in the first
minute as it is worded? In the NERC Glossary, Reportable Disturbance is defined as “Any event
that causes an ACE change greater than or equal to 80% of a Balancing Authority’s or reserve
sharing group’s most severe contingency. The definition of a reportable disturbance is
specified by each Regional Reliability Organization. This definition may not be retroactively
adjusted in response to observed performance.” The definition of Reportable Balancing
Contingency Event should be revised to incorporate this definition, and should be made to
read”…(i) Reportable Disturbance, or…”. With this revision, when BAL-002-1 is retired the
definition of Reportable Disturbance can be retired as well. Regarding the Rationale for

Requirement R1, should Reportable Area Control Error be Reporting ACE? Reporting ACE is in
the NERC Glossary, Reportable Area Control Error is not. In the second paragraph of the
Rationale for Requirement R1 that reads”…as described in R1.3 below…” should be revised to
read “as described in Part 1.3…”. Measure M1 should be revised to read “…that demonstrates
compliance with Parts 1.2 and 1.3.”. In Requirement R2, and Measure M2 “Firm” should not
be capitalized. “Firm Load” is not in the NERC Glossary. It should be revised to read firm Load.
Additional comments: 1) The proposed standard continues with several “compliance traps”
which will hamper operators’ effective use of Contingency Reserves to mitigate reliability
problems, and then could cause compliance exposure due to auditor interpretation. For
example, R1 would require a BA to deploy at least some of its reserves in order to declare an
EEA exemption even if there may not be an immediate need to do so. 2) There are
contradictory portions of the standard which would leave operators confused and again lead
to compliance exposure. a. For example, Part 1.3 (ii) does not include an exemption for
deploying Contingency Reserve for a Contingency that is not a NERC defined Balancing
Contingency Event. R2 does have an exemption for this and other scenarios. The term
"sudden" being included in the definition of a Balancing Contingency Event is the source of
the problem. See the second scenario of Attachment A (sent by E-mail to Darrel Richardson).
b. R1 does not treat subsequent Contingencies in a consistent manner, again related to the
term "sudden" being included in the definition of a Balancing Contingency Event. See the first
scenario in Attachment A (sent by E-mail to Darrel Richardson). 3) There are several problems
with the definitions including definitions of Most Severe Single Contingency (MSSC),
Contingency Event Recovery Period (CERP), and Balancing Contingency Event (BCE). a. MSSC
does not include concurrently dropped load which may cause a Balancing Authority to carry
extra Contingency Reserve beyond its actual MSSC. b. BCE is unclear with regard to both
generation and transmission events. (Also consider if A. Item b within the BCE definition
instead referred to an unplanned change in ACE as opposed to an unexpected change in ACE.)
4) Regarding R2: a. R2 is far more complex than necessary, is unclear, and contains potential
for gaming. b. Much less complicated language is proposed here, based on the original NERC
Policy 1. Suggest the revision of R2 to read: R2. The Responsible Entity, if deficient in
Contingency Reserves, has 90 minutes to restore. If the Responsible Entity experiences a
Reportable Balancing Contingency Event during this time an additional 15 minutes are
allotted.” An alternative suggested rewording of R2: R2. The Responsible Entity shall develop
operational plans that provide sufficient Contingency Reserve considering all other events
that may reduce this amount. This, together with the recovery provision in R1 (results-based
requirement) and the provision in Requirement R6 and Attachment 1 of EOP-011-1 (which
defines EEA levels) would collectively take care of many of the conditions listed in the
proposed Requirement R2 including active monitoring of the amount of reserve to meet the
Contingency Reserve requirement. R2 as presented in this draft requires a BA to demonstrate
ƚŚĂƚŝƚŵĂŝŶƚĂŝŶƐŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ͕ĂǀĞƌĂŐĞĚŽǀĞƌĞĂĐŚůŽĐŬ,ŽƵƌ͕ŐƌĞĂƚĞƌƚŚĂŶŽƌĞƋƵĂů
ƚŽŝƚƐĂǀĞƌĂŐĞůŽĐŬ,ŽƵƌDŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ͕ĞdžĐĞƉƚƵŶĚĞƌĐĞƌƚĂŝŶ
circumstances. If the SDT’s intent is to ensure that a BA consider events other than MSSC that
could reduce the amount of reserve, then to meet this intent we suggest replacing R2 as
shown preceding. We believe this together with the recovery provision in R1 would take care

of many of the conditions listed in the proposed Requirement R2. c. The language in Part 2.2
regarding Operating Instruction appears to allow operating personnel to create exemptions
from R2 at will. d. Requirement R2 continues to not include a number of “grace hours” per
quarter, as requested in some industry comments. It may have a net effect of increasing the
amount of available contingency reserve to some BAs which may marginally increase
ƌĞůŝĂďŝůŝƚLJ͘,ŽǁĞǀĞƌ͕ƚŚŝƐŶĞĞĚƐƚŽďĞďĂůĂŶĐĞĚĂŐĂŝŶƐƚŝŶĐƌĞĂƐĞĚŽƉĞƌĂƚŝŶŐĐŽƐƚƐĚƵĞƚŽ
carrying more reserve. e. Requirement R2 may produce a perverse incentive. A BA may let its
ACE remain negative to keep the reserve monitor numbers above MSSC. Also, without a
number of "grace hours" per quarter, there may be a susceptibility to loads running
unexpectedly hŝŐŚŶĞĂƌƚŚĞĞŶĚŽĨĂůŽĐŬ,ŽƵƌ͕ĐĂƵƐŝŶŐĂŵŝŶŝƐĐƵůĞƐŚŽƌƚĨĂůůƚŚĂƚƌĞƐƵůƚƐŝŶĂŶ
occasional "nuisance" compliance violation. f. R2 also causes BAs to carry much higher
Contingency Reserves than necessary during the latter portions of the hour in order to “make
the numbers come out right” if they are below MSSC in the beginning of the hour. g.
Requirement R2 creates an artificial increase in reserves in order to maintain an amount overand-above that required by the standard to meet non-DCS operational events, thereby
increasing costs to ratepayers for no increase in reliability. h. R2 will encourage operators to
not deploy reserves when needed for reliability in order to meet compliance with this
requirement, which could be detrimental to reliability. i. Entities that have to shed firm
customer load (because load cannot be shed fast enough) to maintain reserves to meet
compliance with this requirement is not an action that should be taken for reliability. j. In our
previous comments, we found Requirement R2 confusing and that the requirement itself was
ƵŶŶĞĐĞƐƐĂƌLJĨŽƌƐŽůŽŶŐĂƐƚŚĞŵĞƚƌĞƋƵŝƌĞŵĞŶƚZϭ͘,ĂǀŝŶŐZϭƚŚĂƚƌĞƋƵŝƌĞƐĂƚŽŵĞĞƚ
the ACE recovery requirement following an MSSC event would suffice to drive the proper
behavior of securing adequate reserve around the clock (except those conditions listed in R1).
If and when a contingency occurs and the affected BA does not have sufficient reserve to
recover ACE, then it will fail R1 whereas if R2 as presented is retained, then a BA could fail
both requirements. There is no need for having R2 to support R1, which can result in double
jeopardy. k. To include the remaining conditions that are not already accounted for under
which a BA may not be able to maintain the required amount AND during which an MSSC
event occurs thereby rendering a BA unable to meet requirement R1, then the following
ďƵůůĞƚĞĚŝƚĞŵŵĂLJďĞĂĚĚĞĚƵŶĚĞƌWĂƌƚϭ͘ϯŝŶZϭ͗ͻtŚĞŶƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJŝƐƵƐŝŶŐŝƚƐ
Contingency Reserve for a period not to exceed 90 minutes, to resolve the excedance of a
System Operating Limit (SOL) or Interconnection Reliability Operation Limit (IROL). 5) The last
ƐĞŶƚĞŶĐĞŽĨŵĞƚƌŝĐDϮǁŚŝĐŚƐƉůŝƚƐĂůŽĐŬ,ŽƵƌŝŶƚŽƐƵď-periods is difficult to follow and
seems to add unnecessary complexity in determining compliance. 6) When the exemption in
WĂƌƚϮ͘ϲďĞĐŽŵĞƐƌĞůĞǀĂŶƚ͕ŝƚŵŽƐƚůŝŬĞůLJǁŝůůŽĐĐƵƌǁŝƚŚŝŶƚŚĞŵŝĚĚůĞŽĨĂůŽĐŬ,ŽƵƌ͘/ƚŝƐŶŽƚ
clear if "instantaneous values showing reserves" refers to the sum of Contingency Reserve
available plus Firm Load that can be shed. 7) Part 1.3 and R2 should be cognizant of
unexpected loss of reserve without it being accompanied by a loss of power being delivered.
In the last posting, we expressed a concern with the term “sudden loss” (see below). We are
unable to find any response in the Summary Consideration report that addresses this
comment. Please consider these comments and provide a response. A Balancing Contingency
Event is vaguely defined as a “Sudden loss of generation...” or “sudden decline in ACE...”. The

word “sudden” is imprecise, and should be clarified. We suggest that the standard be clearer
about defining the start time for a Reportable BCE. We support definitions like that used in
NPCC Directory 5 section 5.17 where it says that the start of an event has occurred when a
specific X amount of MWs are lost in a specific Y amount of time. Therefore, we suggest that
the drafting team add precision in determining minute T+0 for an event by adding the
following sentence (or something like it) to the Reportable BCE definition: “Following the
resource failure, the Reportable BCE starting time is defined as the first chronological rolling
one minute interval that meets the reduction in resource output(s) criteria stated herein.”
The SDT’s response to comment does not appear to address this particular comment. We ask
the SDT to please provide the rationale as to why this suggestion was not adopted. To
summarize, the January 2015 version of BAL-002-2 could be improved by providing better
clarity within the definitions and making simplifications that yield a more "operator-friendly"
standard. There is a concern that the complexity and nuances of the proposed standard in
some circumstances could be a distraction to the operator when more important reliability
tasks need to be performed.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
Agree
PJM
Individual
Leonard Kula
Independent Electricity System Operator
1. In the last posting, we expressed a concern with the term “sudden loss” (see below). We
are unable to find any response in the Summary Consideration report that addresses this
comment. Please consider these comments and provide a response. A Balancing Contingency
Event is vaguely defined as a “Sudden loss of generation...” or “sudden decline in ACE...”. The
word sudden is imprecise, and should be clarified. We suggest that the standard be clearer
about defining the start time for a Reportable BCE. We support definitions like that used in
NPCC Directory 5 section 5.17 where it says that the start of an event has occurred when a
specific X amount of MWs are lost in a specific Y amount of time. Therefore, we suggest that
the drafting team add precision in determining minute T+0 for an event by adding the
following sentence (or something like it) to the Reportable BCE definition: “Following the
resource failure, the Reportable BCE starting time is defined as the first chronological rolling
one minute interval that meets the reduction in resource output(s) criteria stated herein.”
The SDT’s response to comment does not appear to address this particular comment. We ask
the SDT to please provide the rationale as to why this suggestion was not adopted. 2. In our
previous comments, we found Requirement R2 confusing and that the requirement itself was
unnecessĂƌLJĨŽƌƐŽůŽŶŐĂƐƚŚĞŵĞƚƚŚĞƌĞƋƵŝƌĞŵĞŶƚŝŶZϭ͘,ĂǀŝŶŐZϭƚŚĂƚƌĞƋƵŝƌĞƐĂƚŽ
meet the ACE recovery requirement following an MSSC event would suffice to drive the
proper behavior of securing adequate reserve around the clock (except those conditions listed

in R1). If and when a contingency occurs and the affected BA does not have sufficient reserve
to recover ACE, then it will fail R1 whereas if R2 as presented is retained, then a BA could fail
both requirements. There is no need for having R2 to support R1, which can result in double
jeopardy. R2 as presented in this draft requires a BA to demonstrate that it maintains
ŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ͕ĂǀĞƌĂŐĞĚŽǀĞƌĞĂĐŚůŽĐŬ,ŽƵƌ͕ŐƌĞĂƚĞƌƚŚĂŶŽƌĞƋƵĂůƚŽŝƚƐĂǀĞƌĂŐĞ
ůŽĐŬ,ŽƵƌDŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ͕Ğxcept under certain circumstances. If the SDT’s
intent is to ensure that a BA consider events other than MSSC that could reduce the amount
of reserve, then to meet this intent we suggest replacing R2 with the following: R2. The
Responsible Entity shall develop operational plans that provide sufficient Contingency Reserve
considering all other events that may reduce this amount. We believe this together with the
recovery provision in R1 would take care of many of the conditions listed in the proposed
Requirement R2. To include the remaining conditions that are not already accounted for
under which a BA may not be able to maintain the required amount AND during which an
MSSC event occurs thereby rendering a BA unable to meet requirement R1, then the
following ďƵůůĞƚĞĚŝƚĞŵƐŵĂLJďĞĂĚĚĞĚƵŶĚĞƌWĂƌƚϭ͘ϯŝŶZϭ͗ͻtŚĞŶƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJŝƐ
using its Contingency Reserve for a period not to exceed 90 minutes, to resolve the
exceedance of a System Operating Limit (SOL) or Interconnection Reliability Operation Limit
(IROL)
Group
Seattle City Light
WĂƵů,ĂĂƐĞ
Seattle City Light
Seattle City Light supports Balancing Authorities having the flexibility to use Contingency
Reserve to respond to other reliability events and votes affirmative for this ballot. Seattle
would support the draft more, however, if the term "clock hour average" was replaced with
ΗŝŶƐƚĂŶƚĂŶĞŽƵƐǀĂůƵĞΗƚŚƌŽƵŐŚŽƵƚƚŚĞ^ƚĂŶĚĂƌĚ͘hƐŝŶŐ,ŽƵƌůLJĂǀĞƌĂŐĞƐƉůĂĐĞƐĞŶƚŝƚŝĞƐŝŶƚŚĞ
position where they may be incentivized to have less Contingency Reserve than their current
Most Single Severe Contingency for large percentages of key operating hours. From a financial
perspective, there is nothing in this revision stopping a Balancing Authority from having less
Contingency Reserves than their Most Single Severe Contingency during the last 20 to 30
minutes of every steep load pick up hour every day.
Group
Florida Municipal Power Agency
Carol Chinn
Florida Municipal Power Agency
FMPA supports the comments of Duke Energy
Individual
Kathleen Goodman
ISO New England

Agree
NPCC RSC and IRC SRC
Group
Arizona Public Service Company
Kristie Cocco
Arizona Public Service Company
APS would like the Drafting Team to clarify the following question about the draft language.
R1.2 states “A Responsible Entity is not subject to compliance with Requirement R1 when it is
experiencing a Reliability Coordinator approved Energy Emergency Alert Level under which
Contingency Reserves have been activated.” Since only a Balancing Authority can be declared
to be in an RC-approved EEA, how would that impact the RSG that the Balancing Authority is a
member of since that would be how they would be reporting their compliance with R1?
Differently stated, does the RSG that the BA is a member of receive a waiver from R1 if the
member BA is in an RC-approved EEA?
Group
Con Edison, Inc.
Kelly Dash
Consolidated Edison Company of New York
Application Guidelines, Guidelines and Technical Basis, Training Material, Reference Material
and/or other Supplemental Material section: there is no substantial information contained in
this section of the document. Is it the intent of the drafting team to fill-in these sections at a
later date? If so, when would it be completed? If not, why not?
Individual
Terry Bilke
MISO
We commend the drafting team on the effort committed to this project and appreciate the
improvements. We also appreciate the various objectives the team is trying to meet, but
believe it is time to step back and ensure we are moving in a direction where NERC is trying to
go with clearer, results-based standards. We understand that the team is trying to meet their
interpretation of Order No. 693 directives. We respectfully submit that much of what the
FERC directed may be moot as the directives related to primary, secondary, and tertiary
control, have been met by other standards projects. This is particularly true considering the
equally effective R2 (Balancing Authority ACE Limit, BAAL) in BAL-001-2 and a performance
based Frequency Response Standard. The current BAL-002 is well understood by system
operators and performance as posted on the NERC “Adequate Level of Reliability (ALR)
Metrics” website has been stellar. The draft out for comment is not easily understood, adds
complexity, and will likely increase customer cost for no discernable reliability value. If the

standard effort reaches an impasse, it may be time to hold a technical conference to get
resolution on a few key items: 1] What should be the obligation of the Balancing Authority for
events > MSSC? [We suggest that such events are reported to demonstrate best efforts were
made, but compliance is not assessed. The BA is still accountable for BAAL. Finally there are
backstop standards as load shedding is mandated in the EOP and IRO standards for harmful
frequency conditions and IROL exceedances] 2] What constitutes a continent-wide
contingency reserve policy? [We believe the policy could be met by developing simple
definitions for the various categories of operating reserves as any can be used to meet DCS or
the other Balancing Standards in real time. The policy should state that the BA performs an
analysis to develop warning and alarm points for their operators for the reserves needed to
meet BAL-001, BAL-002, and BAL-ϬϬϯ͘,ĂǀŝŶŐƐƉƌŽǀŝĚĞƚŚŝƐĚĂƚa to in real time to their
Reliability Coordinators would add reliability value to the EEA and other EOP processes.
Finally, a guidelines document on reserves approved by the NERC Operating Committee could
be part of this policy] 3] Since there are now performance based BAAL and FRS in place, could
we not actually simplify the current DCS? [Retain a cleaner version of the current R1, and a
simpler R2 that requires presenting reserve values to BA and RC with appropriate alarm
points] 4] The extent the remaining 693 directives have been met by other standards projects.
[We believe BAAL addresses the Commission’s concerns for detecting and responding to
significant high or low frequency events, addresses the concern about performance to
individual events, and is a performance-based double-confirmation of secondary and tertiary
reserves] 5]For those requirements that are ultimately proposed, is there a way to keep them
simple and easy to understand as opposed to being overly precise [For example, if there are
exclusions in a requirement, rather than trying to calculate reserve recovery to the minute,
exclude the hour when the situation occurs and the following hour(s), the number of hours
determined by the extent contingency reserves were depleted)? We agree with comments
submitted by the IRC-SRC and MRO-NSRF as applied to the current draft. The question is
whether to continue to adjust the current draft or make sure we are creating a solution that is
relatively simple to apply and provides reliability value. If we continue down the current path
for the standard, we have two primary concerns. Our first concern is that the lowering of the
threshold to 900 MW in the East, coupled with the proposed change from quarterly average
performance to individual event performance, will increase customer costs for no discernable
reduction in reliability risk. Both DCS performance (ALR statistics) and frequency performance
(NERC Resources Subcommittee minutes) show frequency performance is more than
adequate. As noted by Chairwoman LaFleur at NERC Board meetings, we should consider the
reliability benefits of a standard vs. its costs. Costs will increase with the lower threshold for
our customers. Because the interconnection is over-biased (ACE overstates resource loss) and
dispatchers operate conservatively, our operators will likely deploy set-aside contingency
reserves for any loss over 750 MW rather than wait to double-check the event size. This will
likely add scores of contingency reserve deployment cases each year for situations that could
likely be met by other on-line reserves. Finally, it should be noted that the frequency change
from a 900 MW loss in the East is barely beyond the change from a Time Error Correction. Our
recommendation is that the standard uses the lesser of 80% of MSSC or 1000 MW for the
East. We also recommend that NERC retains the quarterly reporting. Individual cases of non-

compliance can be tallied in the form to achieve the FERC directive, but we believe it is
important that Enforcement assesses compliance base on the aggregate performance of the
BA or RSG, not just spot observations. Our second major concern with the current posting for
comment is that R2 goes beyond the original intent of the DCS. The reason there are no
measures for this requirement in BAL-002-0 is that it was never intended to be a commodity
standard. The predecessor to DCS was Policy 1, which had guidelines on operating reserves.
The first DCS was one of NERC’s first performance-based standards and existed prior to the
ERO. The intent was to retain the concept of the guide to plan to have a certain amount of
reserves. The measures of success were to meet CPS and DCS. DCS’ intent was to respond
quickly to all large events, with performance evaluated on events 80%-100% of MSSC. The
intent of the 90 minute reserve replenishment was to get ready for future events (meaning
you’d be held for compliance to the standard for events 90 minutes thereafter). Another
reason for our concern is that this commodity requirement is being proposed without any
data to support what actually is carried hour to hour across the Interconnections and the
extent operators draw on these reserves to keep their system balanced. If R2 is retained as
proposed, we believe that it should be a “positioning” requirement, not a zero-defect
requirement. As proposed, either customer costs will increase or reliability will be negatively
impacted. The only way to have more than 100% reserves all the time in normal operations is
to carry well more than 100% reserves as a basis of operations or choose not to deploy
reserves for non-reportable events and draw on frequency bias to keep reserves available.
While the proposal provides some exclusions, the requirement should start on the basis that
there will always be some variability and unforeseen non-consequential events that will
require reserve deployment. If retained, we suggest R2 should require contingency reserves >
100% MSSC for 99% of all applicable hours. It should be noted that just because a BA has less
than MSSC in one hour in four days, does not mean that it had zero reserves in that hour.
Additionally, in a multi-BA Interconnection, the odds that the Interconnection would be
deficient in Reserves with a 99% BA standard are astronomical. In a single-BA Interconnection
there are backstops in the EOP and IRO standards. BAL standards are for normal operations.
Other standards protect against events > N-1. Finally, we believe there should be a single
quarterly report for R1 and R2. The R1 portion should be simplified to be very similar to today,
to include reporting of events > MSSC (but not part of compliance evaluation). The quarterly
R2 portion of the report should have the number of non-excluded hours the BA had reserves
< MSSC and an identifier which hours were excludable under 2.1 through 2.6.
Group
SPP Standards Review Group
Robert Rhodes
Southwest Power Pool
BAL-002-2 Shouldn’t ‘transmission’ as used in the definition of Balancing Contingency Event in
A.a.iii. and B. be capitalized? Several standards recently have foregone the Effective Date
section in the standard and instead refer to the Implementation Plan for the specific
implementation dates. Should that be considered here? Use lower case ‘requirement’ in the

3rd line of the Background material. Contingency Reserve should probably be capitalized in
the 1st, 2nd and 4th paragraphs of the Rationale Box for Requirement R2. Delete the ‘s’ on
‘suites’ in the 11th line of the 2nd paragraph of the Rationale Box for Requirement R2.
Shouldn’t ‘load’ be capitalized in the 4th paragraph of the Rationale Box for Requirement R2?
Background Document Consistency is needed throughout the document in the capitalization
of terms such as ‘Transmission’, ‘Contingency Reserve’, ‘requirements’, ‘Transmission Line’,
‘Responsible Entity’, ‘Load’, ‘Real-time’, ‘energy deficient entities’, ‘event’, ‘field trials’ and
‘firm load’. In some situations, the SDT uses ‘SDT’ and in others it simply uses ‘drafting team’.
Be consistent throughout. Replace ‘Balancing Authority or Reserve Sharing Group’ with
‘Balancing Authority (BA) or Reserve Sharing Group (RSG)’ in the 9th line of the 3rd paragraph
on Page 3. Subsequent uses of these terms should then be BA or RSG, respectively. Insert
‘(MSSC)’ immediately following ‘Most Severe Single Contingency’ in the 2nd line of the 2nd
paragraph on Page 4. Replace ‘Standard’ in the 6th line of the same paragraph with
‘standards’. Replace ‘the real-time operations’ with ‘Real-time operations’ in the 1st line of
the 1st paragraph under Balancing Contingency Event on Page 5. Replace ‘requirement’ with
‘directive’ in the last line of the 2nd paragraph under Balancing Contingency Event on Page 5.
Replace the 3rd bullet at the top of Page 7 with the following: ‘resolving the exceedance of a
System Operating Limit (SOL) or Interconnection Reliability Operating Limit (IROL) that
requires the use of Contingency Reserves; and’. Replace ‘requirements’ with ‘directives’ in the
4th line of the 4th paragraph on Page 9. Replace ‘suites’ with ‘suite’ in the 1st line in the 1st
paragraph at the top of Page 10. The SDT is to be commended for the improved clarity in the
examples in Attachment 2. The reference sited in the last line of the 2nd paragraph on Page
34 (Footnote 5) is not attached. It’s referenced in Footnote 5. There is no Footnote 3 as
referenced in the 3rd line of the paragraph under Control Performance Standards (CPS1) on
Page 34. CR Form 1 In cell A15 of the Read Me tab, use lower case ‘it’. In cell A1 of the
Exemption tab, replace ‘Exemp’ with ‘Exempt’. In cells A10 and A16 of the Description tab, ©
appears instead of the intended (c). Thanks Microsoft. In cell A11 of the Entry Instructions tab,
insert ‘with’ between ‘associated’ and ‘subsequent’. In cell A4 of the Calculator tab, insert
‘the’ between ‘Enter’ and ‘name’.
Group
Duke Energy
Colby Bellville
Duke Energy
General Comments: Duke Energy would like to take the opportunity to offer comment on the
overall project concerning BAL-002-2 in conjunction with the recent FERC NOPR issued on
November 20, 2014. FERC issued a NOPR proposing the approval of the BAL-001-2 standard
(Real Power Balancing Control Performance). FERC commented in its NOPR that further
revisions to the BAL-002 standard should take into consideration, the impact the revisions
may have on the Balancing Authority ACE Limit (BAAL) in BAL-001-2. Duke Energy agrees with
the Commission that the potential impact that compliance with BAL-002 may have on BAAL
should be taken into consideration during further modifications to BAL-002, and suggests that

this project be tabled until the final order issuing the approval of BAL-001-2 has been handed
down by FERC. Balancing Contingency Event: Duke Energy would like to re-state its concerns
with the proposed definition of Balancing Contingency Event. Originally, we stated that we
sought clarification on item B of the Balancing Contingency Event (BCE) definition. A BCE
should be predicated on a deviation in Area Control Error (ACE) . As written, we are unclear
why item B is even part of the definition because we believe Item B is redundant with item
A.a.ii. We fail to see the additional clarity that Item B provides, and could see where questions
could arise regarding the differences between the two items in the future. Background: In the
revised background section of the proposed BAL-002-2, the section alludes to frequency
management, however, we fail to see any requirement in this standard pertaining to
frequency management. R1: We would like to offer our previous comment on this
requirement for the drafting team’s consideration. Duke Energy suggests the following
revision to R1.2: “1.2. A Responsible Entity is not subject to compliance with Requirement R1
when it is experiencing an Energy Emergency Alert under which Contingency Reserves have
been utilized to serve load.” We believe the intent of the SDT was for the Responsible Entity
to be exempt from compliance with R1 during those instances where Contingency Reserves
are utilized to serve load. Duke Energy requests further clarification on what is meant by the
reference to activate Contingency Reserves under an Energy Emergency Alert (EEA). R1
Rationale: If the SDT’s intent is to eliminate any potential overlap with other standards, this
will not be the case once the BAAL is in place. If BAL-001-2 is approved, there will be another
standard driving a BA to take corrective action when frequency is hurting. Again, we caution
the SDT that moving forward with the BAL-002-2 project without taking into consideration the
BAAL, could result in conflicting standards. In addition, we believe that there are situations
where compliance with BAL-002 may have a detrimental impact on Interconnection
frequency. For example, as the Disturbance Control Standard (“DCS”) under BAL-002 is
measured event-by-event, a Balancing Authority is required to return its ACE to zero with 15minutes after a Reportable Disturbance (or back to its pre-Disturbance ACE value if that value
was negative). Such a response in the future may be a problem if the Reportable Disturbance
occurs when frequency is above Scheduled Frequency, as over-response required by the
Balancing Authority to ensure compliance with BAL-002 may cause the Balancing Authority to
be above its high BAAL under BAL-001-2. If a generation resource was lost in the middle of the
night during a period of minimum load concerns, numerous available generation resources,
and high Interconnection frequency, BAAL would drive the Balancing Authority to take
appropriate action over a reasonable timeframe. DCS would not consider any of these factors
but would require the Balancing Authority to strictly comply. This strict compliance with BAL002 could have a detrimental impact on Interconnection frequency. R2: Duke Energy requests
further clarification from the drafting team on whether its intent was for the standard to be
worded in such a manner to allow for the waiving of immediate restoration of reserves. Is it
the SDT’s intent to afford an entity the opportunity to wait for a period of 90 minutes, before
requiring the restoration of reserves to take place? Also, Duke Energy suggests a re-ordering
of the sub-requirements for R2. Sub-requirements 2.4 and 2.5 should be first and second on
the list of sub-requirements based on the reasoning that they would be the most common
instances. Regarding sub-requirement 2.6, we feel that clarifications are needed. As written

currently, it is unclear whether an entity has to actually shed load for 2.6 to apply, or if you
have to just be prepared to do so. There are concerns that requiring compliance
documentation to demonstrate that you were prepared to take some action, even though
said action never took place, could be considered onerous. Lastly, upon our review, it could
be argued that some of the sub-requirements appear to mirror closely responsibilities that
are already present in EOP-002. We suggest that the SDT consider delaying implementation of
BAL-002-2 so that it becomes effective after EOP-011-1.
Group
PPL NERC Registered Affiliates
Brent Ingebrigtson
LG&E and KU Energy, LLC
These comments are submitted on behalf of the following PPL NERC Registered Affiliates:
LG&E and KU Energy, LLC; PPL Electric Utilities Corporation, PPL EnergyPlus, LLC; PPL
Generation, LLC; PPL Susquehanna, LLC and PPL Montana, LLC. The PPL NERC Registered
Affiliates are registered in six regions (MRO, NPCC, RFC, SERC, SPP, and WECC) for one or
more of the following NERC functions: BA, DP, GO, GOP, IA, LSE, PA, PSE, RP, TO, TOP, TP, and
TSP. The PPL NERC Registered Affiliates support the comments provided by PJM. In addition,
we submit the following comments: It is not clear how the compliance exemptions in R1.2 and
R2.6 for a Responsible Entity experiencing an EEA would apply to a RSG. Since an RSG cannot
request the RC to declare an EEA , it appears the RSG would be required to maintain MSSC
level reserves regardless of the EEA status of its member BAs. It also appears the RSG could be
found non-compliant with both R1.2 and R2.6 simultaneousl. We suggest that while a
member of a RSG is in an EEA, its MSSC and Contingency Reserve Requirement (the member
BA’s reserve obligation to the RSG) are removed from the RSG. The reconfigured RSG would
continue to maintain the RSG based on the new MSSC and the revised assignment of CRR
among the non-EEA members. The RSG would remain in this configuration for the duration of
the member BA’s EEA. Assigning a Medium VRF to both R1 and R2 is not appropriate – the
reliability impact of not having the required amount of reserves does not seem comparable to
the reliability impact of not recovering ACE after a reportable BCE. The VRF for R2 should be
lower than R1. If R2 cannot be revised as suggested by PJM, an alternative to the average
ůŽĐŬ,ŽƵƌŵĞĂƐƵƌĞŵĞŶƚƉĞƌŝŽĚƐŚŽƵůĚďĞƉƌŽǀŝĚĞĚ͘/ĨƌĞƐĞƌǀĞƐĚŝƉďĞůŽǁƚŚĞD^^ůĂƚĞŝŶĂ
CůŽĐŬ,ŽƵƌ͕ŝƚŝƐĚŽƵďƚĨƵůŝĨĂZĐŽƵůĚĂĐƚŝŶƚŝŵĞƚŽƌĞƐŽůǀĞƚŚĞƐŚŽƌƚĨĂůů͘ůƐŽ͕ǁŚĂƚŝƐƚŚĞ
reliability benefit of an RE acting to increase its reserves if the shortfall occurs earlier in the
ŚŽƵƌ͍/ƚĚŽĞƐŶ͛ƚƐĞĞŵƚŚĞĂǀĞƌĂŐĞůŽĐŬ,ŽƵƌŵĞĂƐƵƌĞŵĞŶƚƉĞƌiod provides an RE much
flexibility in complying with R2 nor does it improve BES reliability. A rolling hourly average or
multi-ůŽĐŬ,ŽƵƌĂǀĞƌĂŐĞǁŽƵůĚďĞĂŶŝŵƉƌŽǀĞŵĞŶƚ͘>-002-2 directly applies only to BAs
and Reserve Sharing Groups, but it states in the definition of Contingency Reserve that the
capacity mandated, “may be provided by resources such as Demand-Side Management
(DSM), Interruptible Load and unloaded generation.” That is, BAs can fulfill their BAL-002-2
obligations only by imposing demands on these other parties, and we would like to know upfront what they will be. This concern is heightened by the addition (effective 4/1/2015) of the

expression, “and discourage response withdrawal through secondary control systems,” to the
NERC Glossary definition of Frequency Bias Setting. This change echoes the statement,
“appropriate outer-loop controls (distributed controls) settings to avoid primary frequency
response withdrawal,” in the NERC Resource Subcommittee’s 2013 Eastern Interconnection
Frequency Initiative Whitepaper,” and “Related outer-loop controls within the DCS, as well as
applicable generating unit or plant controls, should be set to avoid early withdrawal of
primary frequency response,” in NERC’s 2/5/2015 Industry Advisory, Generator Governor
Frequency Response.” Implementation of appropriate governor time delays and droop
settings constitutes a well-defined and technologically justified form of GO involvement in
frequency response improvement, but the term “response withdrawal” is vague and could
cause BAL-002-2 to be misconstrued as authorizing BAs to demand new, frequency responseenhancing services from GOs as a regulatory requirement rather than obtaining them through
market mechanisms.
Individual
Anthony Jablonski
ReliabilityFirst
ReliabilityFirst abstains and offers the following comments for consideration: 1. Requirement
R1, Part 1.1 - ReliabilityFirst suggests using the word “shall” instead of “will” to make
mandatory the use of the noted CR Form 1. The term “shall” indicates a duty on the subject
and is used throughout the NERC Standards in this manner; in this case the responsible entity
has a duty to use CR Form 1, so “shall” is the more appropriate term. ReliabilityFirst
recommends attaching it to the standards along with the following change for consideration:
“The Responsible Entity shall document all Reportable Balancing Contingency Events using
Attachment 1 - CR Form 1.” 2. Measure M2 - The newly included second paragraph within
Measure M2 reads more as an exception to the requirement and does not belong as a
measure. It appears to be guidance to an auditor and should more appropriately be placed in
an RSAW. Furthermore, ReliabilityFirst does not want to encourage missing data as a reason
for not performing the calculation and believes any or as many valid samples of the
Contingency Reserve should be included in the clock hour and should not be excluded from
the evaluation. ReliabilityFirst recommends completely removing the second paragraph
within Measure M2 from the standard.
Group
Associated Electric Cooperative, Inc.
WŚŝůůŝƉ,Ăƌƚ
AECI
AECI respectfully requests that the SDT further consider modifying the Contingency Event
Recovery Period to 30 minutes, or provide empirical evidence that demonstrates a risk to
reliability exists when a Responsible Entity exceeds 15 minutes before recovering their ACE to
the pre-disturbance level. Absent a risk to reliability when exceeding 15 minutes, the use of

30 minutes for the Contingency Event Recovery Period would more closely align with other
reliability standards requirements that relate to operation of the BES during events,
specifically the amount of time allowed for an entity to exceed an IROL.
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
WĂŵĞůĂ,ƵŶƚĞƌ
Southern Company Operations Compliance
In regards to R2.6: In an Energy Emergency Alert Level under which the Responsible Entity no
longer has required Contingency Reserve available provided that the Responsible Entity has
made preparations for interruption of Firm Load to replace the shortfall of Contingency
Reserve to avoid the uncontrolled failure of components or cascading outages of the
Interconnection. For this exemption to apply, the preparations must be initiated within 5
minutes from the time that the Energy Emergency Alert Level is declared. Southern agrees
that a BA should not be required to maintain Contingency Reserves during an applicable
Energy Emergency Alert level (for Southern that would be an EEA3). Our concern is with how
the following sentence is phrased “For this exemption to apply, the preparations must be
initiated within 5 minutes from the time that the Energy Emergency Alert Level is declared.”
We recommend a different approach so that it reads, “For this exemption to apply, the
deficient BA must be able to execute interruption of Firm Load to restore ACE within the
Contingency Event Recovery Period timeframe”. The rationale behind this change is if a
deficient BA can recover ACE within Contingency Event Recovery Period via load shed this
should be an acceptable practice but they must have the ability to execute completely this
action within the Contingency Event Recovery Period timeframe (e.g. 15 minutes). Southern
agrees with the drafting team that in an EEA3 a BA should be able to consider load shed as a
viable practice to maintain ACE and not be required to re-establish Contingency Reserves by
shedding load pre-contingency. The current way the Measure is worded supports this
purposed change.
Individual
^ŝdƌƵĐW,E
,LJĚƌŽ-Quebec TransEnergie
Agree
Group
Peak Reliability
Jared Shakespeare
Peak Reliability

General: BAL standards should be developed as a group and not individually. R1.2: “A
Responsible Entity is not subject to compliance with Requirement R1 when it is experiencing a
Reliability Coordinator approved Energy Emergency Alert Level under which Contingency
Reserves have been activated.” EOP-002-3.1 speaks to the RC initiating/declaring but not
approving an Energy Emergency Alert. It can be argued that parameters are in place to make a
decision on approval but nevertheless there is no mention of approvals nor defined approval
processes within the standard. Suggestion is to revise from “approved” to “initiated/declared”
to remain consistent with EOP-002-3.1. R2: Peak is concerned that using an average clock
hour might allow entities to take advantage. For example, if an entity is deficient the first 30
minutes but sufficient the second 30 minutes, the average clock hour would be met but the
first 30 minutes would be in an unreliable state.
Individual
Catherine Wesley
PJM Interconnection
1. Please provide any issues you have on this draft of the BAL-002-2 standard and a proposed
solution. Comments: PJM appreciates and recognizes the work of the SDT as reflected in the
present posting of the proposed BAL-002-2. PJM strongly urges the SDT to incorporate the
following changes. R1 Suggested changes: R1. The Responsible Entity experiencing a
Reportable Balancing Contingency Event shall, within the Contingency Event Recovery Period,
demonstrate recovery by returning its Reporting ACE to at least the recovery value of:
΀sŝŽůĂƚŝŽŶZŝƐŬ&ĂĐƚŽƌ͗DĞĚŝƵŵ΁΀dŝŵĞ,ŽƌŝnjŽŶ͗ZĞĂů-ƚŝŵĞKƉĞƌĂƚŝŽŶƐ΁ͻĞƌŽ͕;ŝĨŝƚƐWƌĞReporting Contingency Event ACE Value was positive or equal to zero); however, during the
Contingency Event Recovery Period, any Balancing Contingency Event event that occurs shall
reduce the required recovery: (i) beginning at the time of, and (ii) by the magnitude of, each
ŝŶĚŝǀŝĚƵĂůĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJĞǀĞŶƚ͕Žƌ͕ͻ/ƚƐWƌĞ-Reporting Contingency Event ACE Value,
(if its Pre-Reporting Contingency Event ACE Value was negative); however, during the
Contingency Event Recovery Period, any Balancing Contingency Event event that occurs shall
reduce the required recovery: (i) beginning at the time of, and (ii) by the magnitude of, each
individual Balancing Contingency Eventevent. 1.2. A Responsible Entity is not subject to
compliance with Requirement R1 when it is experiencing a Reliability Coordinator approved
declared Energy Emergency Alert Level under which Contingency Reserves have been
activated or depleted below reserve requirements. 1.3. Requirement R1 (in its entirety) does
ŶŽƚĂƉƉůLJ͗ͻ;ŝͿǁŚĞŶƚŚĞZĞƐƉŽŶƐŝďůĞŶƚŝƚLJĞdžƉĞƌŝĞŶĐĞƐĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƚŚĂƚ
ĞdžĐĞĞĚƐŝƚƐDŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ͕Žƌͻ;ŝŝͿĂĨƚĞƌŵƵůƚŝƉůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJ
Events and/or Contingency events that are not Balancing Contingency Events for which the
combined magnitude exceeds the Responsible Entity's Most Severe Single Contingency for
those events that occur within a 105-ŵŝŶƵƚĞƉĞƌŝŽĚ͕Žƌͻ;ŝŝŝͿǁŚĞŶƚŚĞZĞƐƉŽŶƐŝble Entity is
operating under the conditions described in R2, in its entirety. R1 Discussion: PJM views it as
necessary to include the MW losses associated with units that may ramp down or be derated
which also result in a loss of output or capacity. CR Form 1 needs to be modified to account
for the suggested changes in R1. R2 Suggested changes: R2. The Responsible Entity shall

develop and maintain an Operating Plan to procure Contingency Reserve capacity for each
hour greater than or equal to its Most Severe Single Contingency for that hour. R2 Discussion:
PJM urges incorporation of our suggested revision to R2. PJM would be supportive of a
standard that incorporated our proposed revision. This revision recognizes that the
procurement of Contingency Reserves is accomplished in the Operation Planning time horizon
and that R2 as presently drafted is overly prescriptive. R2.6 Suggested Changes: Should the
presently drafted R2 and associated sub-requirements remain in the standard, PJM believes
R2.6 is not acceptable in its present language. A necessary revision would be as follows: R2.6.
in an Energy Emergency Alert Level under which the Responsible Entity no longer has required
Contingency Reserve. available provided that the Responsible Entity has made preparations
for interruption of Firm Load to replace the shortfall of Contingency Reserve to avoid the
uncontrolled failure of components or cascading outages of the Interconnection. For this
exemption to apply, the preparations must be initiated within 5 minutes from the time that
the Energy Emergency Alert Level is declared. R2.6 Discussion: Load shedding plans are
adequately addressed in the EOP standards. Requirement R2.6 as proposed is a distraction for
the System Operator that has no positive impact on reliability. The requirement as written
requires that Firm Load be shed to replace a shortfall of Contingency reserves. Why would an
entity shed load to maintain reserves when shedding load via SCADA can be accomplished
quicker than loading Contingency Reserves?
Group
ACES Standards Collaborators
Jason Marshall
ACES
(1) The Most Severe Single Contingency definition and applicability section 4.1.1.1 should be
modified to reflect that the standard simply applies to a BA or RSG by striking “that is not
participating as a member of a RSG at the time of the event”. This language may conflict with
existing RSG contracts. Furthermore, it is a registration issue on whether the standard applies
to the BA or RSG in these situations. When the RSG registers with NERC, NERC will typically
review the contract to understand how the RSG is formed. If the standard should apply to the
BA in certain situations and the RSG in others, this should be documented in a coordinated
functional registration, not in a standards definition or applicability section. What does it even
mean to be in “active status” under applicability section 4.1.1.1? (2) Please strike the last
sentence of the Reportable Balancing Contingency Event. It is administrative in nature and
should be handled through compliance monitoring processes. If NERC wants to know if an
entity has modified its reportable threshold, they have a myriad of compliance monitoring
processes and tools to gather this information. It does not need to be documented in a
glossary definition. Furthermore, it is not really a definition but rather an explanation and
therefore, does not belong in the definition. (3) We continue to believe that the thresholds
defined in the Reportable Balancing Contingency Event are arbitrary. We ask that the drafting
team provide a technical basis for the values instead of the existing explanation in the
Background document. While we understand that the drafting team reviewed some data,

there are uncertainties regarding how values were identified from the data and then another
value was selected. (4) We are confused about the “one-minute interval that defines a
Balancing Contingency Event” language in the Contingency Event Recovery Period definition.
We can find no reference to “one-minute” in the Balancing Contingency Event definition.
There is, however, such a reference in the Reportable Balancing Contingency Event.
Furthermore, the one-minute interval really does not define the event but rather predisturbance level before the start of the event. The language in the Contingency Event
Recovery Period needs to be cleaned up to reflect this information. (5) We disagree with the
definition of Contingency Reserve. The definition should be modified to simply reflect that
Contingency Reserve Is unloaded on-line generation and quick start off-line generation
capable of being dispatched in 15 minutes. The current definition may limit the use of
Contingency Reserve and may omit off-line quick start generation since unloaded generation
usually refers to on-line generators. (6) Reportable Area Control Error in the Rationale box for
R1 should be changed to Reporting ACE to match the NERC Glossary. (7) The insertion of the
“Reliability Coordinator approved” in Part 1.2 creates additional confusion by implying that an
EEA can be issued without RC approval. An EEA cannot be issued without RC approval. Thus,
this language is superfluous, only adds ambiguity and confusion to the part and should be
struck. (8) Although, we do not oppose the use of CR Form 1, Part 1.1 should be struck as it is
administrative in nature. A violation of Part 1.1 could never result in a harm to reliability. If an
entity were to report the data in another format, reliability would not be harmed. If reliability
cannot be harmed then a standard should not compel the action (in this case, specific use of a
reporting form). Use of a CR Form 1 can and should be handled through NERC compliance
monitoring processes as NERC and the Regional Entities do with other reporting formats and
data collection methods. Use of CR Form 1 is already documented in the RSAW which should
be sufficient. (9) While we appreciate that the drafting team did attempt to document other
acceptable uses of Contingency Reserve in R2 that would not violate the requirement, we
fundamentally disagree with the arbitrary selection of 90 minutes as a limit on the use of
Contingency Reserve. Why should use of Contingency Reserve be limited to 90 minutes for an
Energy Emergency? An Energy Emergency could last several hours and BA would be forced to
either violate the requirement or shed load to avoid a compliance requirement. Neither is a
good outcome. Rather, we suggest the 90 minute period should be dropped in Parts 2.1, 2.2,
and 2.3. We particularly see this as an issue for Part 2.2. If an RC were to issue an Operating
Instruction to use Contingency Reserve to resolve an EEA to avoid shedding load, why should
this higher level authority not be able to instruct the BA to exceed the 90 minutes? The fact
that Contingency Reserve may be used for longer than 90 is even documented in the second
to last paragraph on page 36 of the background document. (10) We disagree with the
arbitrary selection of five minutes in Part 2.6 for the exemption to apply. We believe the five
minutes is arbitrary and language is ambiguous which will only lead to inconsistent
compliance outcomes. What would be considered preparations? Sending techs to the
stations? Arming loading shedding schemes? Thinking about it? There needs additional
clarification in the standard. (11) We disagree with the move from quarterly reporting to
exception reporting. Today, compliance is assessed on a quarterly basis. This standard
appears to require a Responsible Entity to issue a self-report anytime it does not recover

100% from a reportable a Reportable Balancing Contingency Event without any basis
identified for the change. This will serve to increase a Responsible Entities compliance costs
without any commensurate benefit to reliability. Furthermore, it will eliminate a data source
that NERC uses for its annual state of reliability report which will be detrimental to the report.
(12) In Measure 2, we suggest adding a clause to the first bullet that Contingency Reserve
must meet or exceed the required amount “unless one of the exceptions from R2 is met”. (13)
In Measure 2, we are confused by the language “excluded by rule in Requirement R2”. Does
this mean excluded by Parts 2.1 through 2.6? If so, change the language to “excluded by Parts
2.1, 2.2, 2.3, 2.4, 2.5 or 2.6”. (14) The VSLs for Requirement R2 should be modified to state
that Responsible Entity did have less than the required amount of Contingency Reserve “and
did not meet one of the exceptions in Parts 2.1 through 2.6”. (15) We are concerned that the
requirement formatting of the exceptions in Part 2.1 through 2.6 are not consistent with the
informational filing NERC submitted to FERC several years ago regarding the use of bullets and
parts in place of sub-requirements. In that filing, NERC stated that numbered lists or “Parts”
would be used when all “Parts” must be met and “bullets” would be used when there are
exceptions. To qualify for an exception, only one of the Parts 2.1-2.6 should be met not all.
Yet, use of a numbered list implies that all exceptions must be met. The formatting needs to
be modified to bullets instead of a numbered list.
Individual
Christina Bigelow
ERCOT
ISO/RTO Council Standards Review Committee
ERCOT commends the drafting team on their efforts to improve BAL-002-Ϯ͘,ŽǁĞǀĞƌ͕ŝƚŚĂƐ
concerns and recommendations regarding the proposed modifications. These concerns and
recommendations are described below by Requirement. Proposed revisions are italicized. 1.
Definitions – ERCOT reiterates its previous comments regarding the Reportable Balancing
Contingency Event thresholds contained within the definition of a Reportable Balancing
Contingency Event. ERCOT believes that the introduction of various, differing thresholds
creates unnecessary complexity and would propose a 1000 MW threshold for its
interconnection as such threshold aligns with the current practice. Further, ERCOT reports
other, smaller events to NERC and its Regional Entity through different mechanisms and,
therefore, with differing reporting thresholds, the same event can be reported to NERC
multiple times under different requirements. Accordingly, since the threshold limits relate
only to reporting and associated documentation, ERCOT respectfully submits that lowering
the reportable event thresholds does not provide any benefit to reliability. 2. Requirement R1
– Recommend modifying the addition (Reliability Coordinator Approved) to Reliability
Coordinator Issued. 3. Requirement R1.2 and Requirement R1.3 – ERCOT recommends the
consolidation of R1.2 and R1.3 and additional revisions as follows: 1.2. A Responsible Entity is
ŶŽƚƐƵďũĞĐƚƚŽĐŽŵƉůŝĂŶĐĞǁŝƚŚZĞƋƵŝƌĞŵĞŶƚZϭǁŚĞŶ͗ͻ/ƚŝƐĞdžƉĞƌŝĞŶĐŝŶŐĂZĞůŝĂďŝůŝƚLJ
Coordinator issued Energy Emergency Alert Level under which Contingency Reserves have
ďĞĞŶĂĐƚŝǀĂƚĞĚŽƌĚĞƉůĞƚĞĚ͘ͻ/ƚĞdžƉĞƌŝĞŶĐĞƐĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƚŚĂƚĞdžĐĞĞĚƐŝƚƐ
DŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJͻ/ƚŚĂƐĞdžƉĞƌŝĞŶĐĞĚŵƵůƚŝƉůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐ

for which the combined MW loss exceeds the Responsible Entity's Most Severe Single
Contingency for those events that occur within a 105-minute period. ERCOT recommends
modifications to subpart 1 regarding the depletion of contingency reserves because
contingencies that deplete reserves can occur without formal “activation” of reserves and
without a “sudden” or triggering event. Thus, it respectfully suggests that the requirement
should be modified to ensure that acknowledgment of such reserve depletion. ERCOT further
recommends revision to subpart 1 because partially loaded generators may experience
contingencies that remove MW from the BA, which may reduce the availability of reserves
maintained by such resources as headroom. In such a circumstance, it is possible to have
multiple contingencies where the MW loss is less than the MSSC, but that result in significant
or complete reserve depletion for the BA. Accordingly, ERCOT recommends that subpart 3 be
clarified to ensure that the loss to which the subpart would be applicable is clear and
unambiguous. By accounting for overall MW of loss, not the magnitude of capacity loss, the
applicability of Subpart 3 would be objective and easily discerned. 4. Requirement R2 –ERCOT
respectfully submits that, as proposed, Requirement R2 would result in the unnecessary
diversion of attention and resources during real-time operations to ensuring that data
recordation and documentation occurred – rather than the performance of activities that are
more directly associated with sustaining the reliability of the Bulk Electric System, e.g.,
contingency reserve mix, monitoring, deployments, etc. Accordingly, ERCOT respectfully
suggests the following alternative revisions, which it believes more closely aligns with the
Commission’s directives: R2. The Responsible Entity shall plan to procure Contingency Reserve
greater than or equal to its Most Severe Single Contingency, except during one or more of the
following periods when the Responsible Entity is: [Violation Risk Factor: Medium] [Time
,ŽƌŝnjŽŶ͗ZĞĂů-time Operations] 2.1 using its Contingency Reserve, for a period not to exceed
90 minutes, to mitigate the reliability concerns associated with Contingencies that are not
Balancing Contingency Events; and/or 2.2 using its Contingency Reserve, for a period not to
exceed 90 minutes, to respond to an Operating Instruction requiring the use of Contingency
Reserve; and/or 2.3 using its Contingency Reserve for a period not to exceed 90 minutes, to
resolve the exceedance of a System Operating Limit (SOL) or Interconnection Reliability
Operation Limit (IROL) that requires the use of Contingency Reserve; and/or 2.4 in a
Contingency Reserve Restoration Period; and/or 2.5 in a Contingency Event Recovery Period;
and/or 2.6 in an Energy Emergency Alert Level under which the Responsible Entity no longer
has required Contingency Reserve available provided that the Responsible Entity has made
preparations for interruption of Firm Load to replace the shortfall of Contingency Reserve to
avoid the uncontrolled failure of components or cascading outages of the Interconnection.
For this exemption to apply, the preparations must be initiated within 5 minutes from the
time that the Energy Emergency Alert Level is declared. Measure 2 could then be modified as
follows: Compliance may be ĂĐŚŝĞǀĞĚďLJĚĞŵŽŶƐƚƌĂƚŝŶŐƚŚĂƚ͗ͻdŚĞĂůĂŶĐŝŶŐƵƚŚŽƌŝƚLJ͛Ɛ
Operating Procedures require procurement of Contingency Reserve amounts that meet or
exceed the Contingency Reserve required to respond to its Most Severe Single Contingency;
Žƌ͕ͻŽŶƚŝŶŐĞŶĐLJZĞƐerve has been restored to the required Contingency Reserve levels
ǁŝƚŚŝŶƚŚĞƐƉĞĐŝĨŝĞĚƉĞƌŝŽĚ͖Žƌ͕ͻƚŚĞƐƵŵŽĨƚŚĞŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞĂŶĚ&ŝƌŵ>ŽĂĚĂǀĂŝůĂďůĞ
as a substitute for unavailable Contingency Reserve reaches the required Contingency

Reserve level within the specified period; Failure of the Balancing Authority to procure
adequate Contingency Reserve to respond to its MSSC and/or recover the required
Contingency Reserve level within the time periods prescribed would be considered an
exception and should be reported quarterly. ERCOT suggests this alternative because the
directive being addressed required development of a continent wide contingency reserve
policy, but did not require or prescribe tracking or reporting obligations. The proposed
modifications appear to not only address a proposed reserve policy, but appear to also be
revising the current quarterly reporting and prescribing an hourly tracking and recordation,
actions and obligations for which ERCOT has been unable to identify an associated directive.
Such additions will likely have unintended consequences in how Reserve Sharing Groups (RSG)
will operate. In particular, the failure or delay of a contingency resource start can result in
recovery performance that is assigned a very low score for that single event, even where
recovery is only a minute or two late. Such outcome would be an inaccurate indicator of the
overall success of the recovery, the overall recovery performance, and the Responsible
Entity’s efforts to recover. Further, there are RSGs whose purpose is to mitigate such risk by
deploying reserves for much smaller events, helping reliability through quick recovery from
smaller events, faster replenishment of reserves, and opportunity for operators to gain
necessary experience regarding reserve deployment. Should each recovery event become
individually sanctionable, RSGs will likely modify their rules to increase their reportable
threshold to the interconnection minimum, which would reduce the net benefits to grid
reliability discussed above. Additionally, the current quarterly reporting has provided an
important data source that is used for NERC’s RAPA group and the State of Reliability Report:
http://www.nerc.com/pa/RAPA/ri/Pages/DCSEvents.aspx. The transition away from quarterly
reporting to only exception reporting will eliminate that data source and reduce overall
visibility. To facilitate the identification of exceptions while maintaining the value and benefits
associated with quarterly reporting, ERCOT recommends that there be a single quarterly
report for all data collected. In such a report, the Requirement R1 portion would be very
similar to the current reporting form with an additional portion where instances of reserve
amounts that were less than the MSSC during the quarter could be reported. Such
coordinated reporting would allow both the ERO and the industry to evaluate reserve and
contingency data concurrently, providing the opportunity to identify any trends and/or
dependencies. ERCOT respectfully submits that the requirement to plan for and procure
reserves greater than or equal to a BA’s MSSC is an appropriate continent-wide contingency
reserve policy and that such policy, when considered in coordination with obligations set
forth within other approved reliability standards such as EOP-011-1 (Requirement R6), IRO005-3.1 (Requirement R2), and TOP-002-2.1b (Requirements R5 – R8) are more than adequate
to ensure reliability. Further, ERCOT would suggest that hourly calculation and/or
demonstration of reserve amounts is: (1) not necessary when reserve requirements are
considered in pari materia with other reliability standards obligations of BAs as described
above, (2) unduly burdensome, and (3) a threat to reliability due to the diversion of resources
that would be necessary to sustain compliance. Quarterly reporting of Reportable Balancing
Contingency Events along with the reporting of reserve amounts less than a BA’s MSSC are
more than sufficient for both the ERO and responsible BAs to identify and address

contingency reƐĞƌǀĞŝƐƐƵĞƐƚŚĂƚǁŽƵůĚƚŚƌĞĂƚĞŶƌĞůŝĂďŝůŝƚLJ͘,ĞŶĐĞ͕ƌĞƋƵŝƌŝŶŐƐƚŽƉƌŽǀŝĚĞ
documentation of contingency reserves averaged over a clock hour is an onerous, purely
administrative obligation that elevates documentation over reliability. Thus, ERCOT
recommends that Requirement R2 be revised as set forth above. ERCOT thanks you for the
opportunity to comment upon the proposed Revisions to BAL-002-2 and respectfully suggests
that, as NERC continues its effort to move away from zero defect standards, Requirement R2
be revised as recommended above to support that concept. Should the ERO wish to provide
additional guidance regarding the mix or management of Contingency Reserves, it should
consider the development and publication of a Reliability Guideline.
Group
Bonneville Power Administration
Andrea Jessup
Transmission Reliability Standards Group
BPA is in agreement with the proposed standard, however, believes there should be a
clarifying comment in requirement R1. In R1, following both sub-bullets of R1, BPA would like
to state: “For all subsequent events that occur during the initial Contingency Event Recovery
Period, the Pre-Reporting Contingency Event ACE Value for that initial event must be used for
the subsequent event(s).” Finally, BPA proposes that R2 2.6 spells out that it only pertains to
an EEA3. The reason for this is that exemption only applies to EEA level 3 in EOP-011-1
Emergency Operations. In that new standard, EEA 3 is defined, in part, as a situation where
“The energy deficient Balancing Authority is unable to meet minimum Contingency Reserve
requirements.” EEA 2 language clearly states that while a BA can no longer meet all of its
expected energy requirements: “An energy deficient Balancing Authority is still able to
maintain minimum Contingency Reserve requirements.”
Individual
Richard Vine
California ISO
Agree
ISO/RTO Council Standards Review Committee
Group
ISO/RTO Council Standards Review Committee
Charles Yeung
SPP
1. The SRC generally supports R1. For clarity, and to address a concern that events that do not
sudden as defined in the term “Balancing Contingency Event” (such as ramping, derating, etc.)
are excluded from the recovery consideration, the SRC suggests the following minor
clarification to R1 for consideration: R1. The Responsible Entity experiencing a Reportable
Balancing Contingency Event shall, within the Contingency Event Recovery Period,
demonstrate recovery by returning its Reporting ACE to at least thĞƌĞĐŽǀĞƌLJǀĂůƵĞŽĨ͗ͻĞƌŽ͕

(if its Pre-Reporting Contingency Event ACE Value was positive or equal to zero); however,
during the Contingency Event Recovery Period, any Contingency event that occurs shall
reduce the required recovery: beginning at the time of, and by the magnitude of, each
ŝŶĚŝǀŝĚƵĂůŽŶƚŝŶŐĞŶĐLJĞǀĞŶƚ͕Žƌ͕ͻ/ƚΖƐWƌĞ-Reporting Contingency Event ACE Value, (if its PreReporting Contingency Event ACE Value was negative); however, during the Contingency
Event Recovery Period, any Contingency event that occurs shall reduce the required recovery:
beginning at the time of, and by the magnitude of, each individual Contingency event. (i.e.,
strike out (i) and (ii)) We further suggest Part 1.2 be revised to read: 1.2. A Responsible Entity
is not subũĞĐƚƚŽĐŽŵƉůŝĂŶĐĞǁŝƚŚZĞƋƵŝƌĞŵĞŶƚZϭǁŚĞŶ͗ͻ/ƚŝƐĞdžƉĞƌŝĞŶĐŝŶŐĂZĞůŝĂďŝůŝƚLJ
Coordinator issued Energy Emergency Alert Level under which Contingency Reserves have
ďĞĞŶĂĐƚŝǀĂƚĞĚŽƌĚĞůĞƚĞĚ͘ͻ/ƚĞdžƉĞƌŝĞŶĐĞƐĂĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƚŚĂƚĞdžĐĞĞĚƐŝƚƐ
DŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ͘ͻ/ƚŚĂƐĞdžƉĞƌŝĞŶĐĞĚŵƵůƚŝƉůĞĂůĂŶĐŝŶŐŽŶƚŝŶŐĞŶĐLJǀĞŶƚƐ
and/or Contingency events that are not Balancing Contingency Events for which the combined
MW loss exceeds the Responsible Entity's Most Severe Single Contingency for those events
that occur within a 105-minute period. 2. In our previous comments, the SRC stated that it
found Requirement R2 confusing and that the requirement itself was unnecessary for so long
ĂƐƚŚĞŵĞƚƚŚĞƌĞƋƵŝƌĞŵĞŶƚŝŶZϭ͘,ĂǀŝŶŐZϭƚŚĂƚƌĞƋƵŝƌes a BA to meet the ACE recovery
requirement following an MSSC event would suffice to drive the proper behavior of securing
adequate reserve around the clock (except those conditions listed in R1). If and when a
contingency occurs and the affected BA does not have sufficient reserve to recover ACE, then
it will fail R1 whereas if R2 as presented is retained, then a BA could fail both requirements.
There is no need for having R2 to support R1, which can result in double jeopardy. Note:
ERCOT does not support this comment. 3. In addition, the proposed R2 has the following
ƉŽƚĞŶƚŝĂůĂĚǀĞƌƐĞĐŽŶƐĞƋƵĞŶĐĞƐ͗ͻŶŝŶĐƌĞĂƐĞŝŶƌĞƐĞƌǀĞƐŝŶŽƌĚĞƌƚŽŵĂŝŶƚĂŝŶĂŶĂŵŽƵŶƚ
over-and-above that required by the standard to meet non-DCS operational events,
therefore, costing the rate payers additional monies for no increase in reliability (Note: IESO
ĚŽĞƐŶŽƚƐƵƉƉŽƌƚƚŚŝƐĐŽŵŵĞŶƚͿ͖ͻKƉĞƌĂƚŽƌƐŶŽƚĚĞƉůŽLJŝŶŐƌĞƐĞƌǀĞƐǁŚĞŶŶĞĞĚĞĚĨŽƌ
reliability in order to meet compliance with this requirement, which could be detrimental to
reliaďŝůŝƚLJ͖ĂŶĚͬŽƌͻŶƚŝƚŝĞƐƐŚĞĚĚŝŶŐĨŝƌŵĐƵƐƚŽŵĞƌůŽĂĚƚŽŵĂŝŶƚĂŝŶƌĞƐĞƌǀĞƐƚŽŵĞĞƚ
compliance with this requirement, which, again, is not the right action to take for reliability. 4.
We understand that the intent of the proposed R2 is to require a BA to demonstrate that it
ŵĂŝŶƚĂŝŶƐŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞ͕ĂǀĞƌĂŐĞĚŽǀĞƌĞĂĐŚůŽĐŬ,ŽƵƌ͕ŐƌĞĂƚĞƌƚŚĂŶŽƌĞƋƵĂůƚŽŝƚƐ
ĂǀĞƌĂŐĞůŽĐŬ,ŽƵƌDŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ͕ĞdžĐĞƉƚƵŶĚĞƌĐĞƌƚĂŝŶĐŝƌĐƵŵƐƚĂŶĐĞƐ͘/Ĩ
the SDT’s intent is to ensure that a BA consider events other than MSSC that could reduce the
amount of reserve, then to meet this intent we suggest replacing R2 with the following: R2.
The Responsible Entity shall develop operational plans that provide sufficient Contingency
Reserve considering other events that may reduce this amount. We believe this together with
the recovery provision in R1 and the provision in Requirement R6 and Attachment 1 of EOP011-1 would collectively take care of many of the conditions listed in the proposed
Requirement R2 including active monitoring of the amount of reserve to meet the
Contingency Reserve requirement. To include the remaining conditions that are not already
accounted for under which a BA may not be able to maintain the required amount AND
during which an MSSC event occurs thereby rendering a BA unable to meet requirement R1,

ƚŚĞŶƚŚĞĨŽůůŽǁŝŶŐďƵůůĞƚĞĚŝƚĞŵƐŵĂLJďĞĂĚĚĞĚƵŶĚĞƌWĂƌƚϭ͘ϯŝŶZϭ͗ͻtŚĞŶƚŚĞZĞƐƉŽŶƐŝďůĞ
Entity is using its Contingency Reserve for a period not to exceed 90 minutes, to resolve the
exceedance of a System Operating Limit (SOL) or Interconnection Reliability Operation Limit
(IROL) Note: ERCOT does not support this comment.
Additional Comments
Joe Spencer/SERC/OC Review Group
We have the following questions and concerns with the language in the Applicability subsections for 4.1.
Section 4.1.1.1 is problematic in that it states that the RSG is the RE when BA’s are in ‘active
status’. Active status is subjective and likely not a defined term in governing RSG agreements.
Additionally, the definition cannot be applied consistently to both R1 and R2. Please consider the
following examples where a BA is assumed to be actively maintaining its reserve allocation for the
RSG. o A BA experiences a Reportable Event in which it recovers ACE and reserves in accordance with
R1 without requesting assistance from the RSG members. The BA is the RE even though it is in ‘active
status’ in the RSG. o For R2 compliance purposes, as long as the BA is actively maintaining its allocation
of reserves in accordance with the governing RSG agreement, the RSG is the RE. o Applicability for R2 is
further complicated when the BA may participate in an RSG for only part of its footprint and maintains
its allocation for the RSG while also maintaining additional reserves for the MSSC in the overall balancing
area. In this example, both the BA and the RSG are may be RE’s. We believe that to resolve these issues,
the BA versus RSG applicability should be moved to the requirements themselves. The SDT could also
consider explicitly stating that a BA is compliant under R2 when it maintains the average hourly reserves
at least equal to its reserve allocation under the terms of the governing RSG agreement.R1 - clarity
needs to be added to phase “(i) beginning at the time of” to explain how this phrase applies. 2. We
recommend the following change to the proposed language of R1.1.R1.1 All Reportable Balancing
Contingency Events will be documented using CR Form 1 [or an acceptable alternative.] 3. We
recommend the following change to the proposed language of R1.2.R1.2. A Responsible Entity is not
subject to compliance with Requirement R1 when it is experiencing an Energy Emergency Alert Level
under which Contingency Reserves have been activated [or where the Responsible Entity has declared
that it may be unable to meet reserve requirements due to system conditions.]R1.2 Comment: The
proposed language is counterintuitive and creates a compliance trap for the System Operator. A BA may
declare an EEA3 (under the revised language of yet to be approved EOP-011) indicating that it is unable
to meet reserve requirements, but must deploy some of those reserves even if there is no immediate
need to do so, to receive an R1 compliance exemption, making the BA even less able to meet its reserve
requirements.Further, if a BA declares an EEA, indicating that it is unable to meet reserve requirements,
and subsequently deploys some of its reserves to meet increased load does this constitute a deployment
of contingency reserves under R1.2 and what evidence does the BA provide to demonstrate
compliance?4. We recommend the following changes to the proposed language of R2.R2. The
Responsible Entity shall maintain Contingency Reserve, averaged ŽǀĞƌĞĂĐŚůŽĐŬ,ŽƵƌ͕ŐƌĞĂƚĞƌƚŚĂŶŽƌ
ĞƋƵĂůƚŽŝƚƐĂǀĞƌĂŐĞůŽĐŬ,ŽƵƌDŽƐƚ^ĞǀĞƌĞ^ŝŶŐůĞŽŶƚŝŶŐĞŶĐLJ͕ĞdžĐĞƉƚĚƵƌŝŶŐƉĞƌŝŽĚƐǁŚĞŶƚŚĞ
ZĞƐƉŽŶƐŝďůĞŶƚŝƚLJŝƐŝŶ͗΀sŝŽůĂƚŝŽŶZŝƐŬ&ĂĐƚŽƌ͗DĞĚŝƵŵ΁΀dŝŵĞ,ŽƌŝnjŽŶ͗ZĞĂů-time Operations] o a
restoration period because it has used its Contingency Reserve for Contingencies that are not Balancing

Contingency Events. This required restoration begins when the Responsible Entity’s Contingency
Reserve falls below its MSSC and must not exceed 90 minutes; and/or o response to a Reliability
Directive; and/or o a Contingency Event Recovery Period or its subsequent Contingency Reserve
Restoration Period; and/or o an Energy Emergency Alert Level under which Contingency Reserves have
been activated [or where the Responsible Entity has declared that it may be unable to meet reserve
requirements due to system conditions.]R2 Comment: As stated in the comments for R1.2, the proposed
language is counterintuitive and creates a compliance trap for the System Operator. A BA may declare
an EEA3 (under the revised language of yet unapproved EOP-011) indicating that it is unable to meet
reserve requirements, but must deploy some of those reserves even if there is no immediate need to do
so, to receive an R2 compliance exemption, making the BA even less able to meet its reserve
requirements.Additionally, absent the suggested language in the first bullet, a BA may receive a
Reliability Directive from its RC (see IRO-001 R8) to deploy Contingency Reserves to mitigate a condition
or event that is having an adverse reliability impact on the BES, but be non-compliant under R2 for
following that directive.We believe that R2, as currently proposed, is unnecessary to satisfy the directive
in FERC Order 693 to develop “a continent-wide contingency reserve policy”, as this was accomplished
with the development of Reliability Guideline: Operating Reserve Management that was approved by
the NERC Operating Committee in October 2013. If, however, the SDT decides that it is necessary to
keep the commodity obligations currently proposed in R2, we believe that the suggested R2 changes
above will reduce unintended adverse reliability consequences while further reinforcing satisfaction of
the directive. Additional Comments:The SDT has failed to demonstrate a performance need, in the form
of negative historical trends for DCS recovery or compliance, for the proposed changes. Significant
negative consequences of the proposed standard include but are not limited to:1) The proposed
language moves this project from being a performance based standard to a commodity obligation.2)
Creates a daunting and unnecessary administrative burden in tracking the commodity obligations set
forth in Requirement 2. For example, the following are just a few of the evidence requirements in the
RSAW: a. R2 requires dated documentation that demonstrates that hourly Contingency Reserves were
at least equal to hourly MSSC. In a three year audit period that is 26,280 one hour intervals! b. Both R1
& R2 require dated documentation for all Reportable Balancing Contingency Events that occur when an
EEA and Contingency Reserves have been activated. When an RE declares an EEA2 or EEA3, under the
current TOP standard, they are declaring that they may be unable to meet required reserve
requirements. When the load increases after the EEA has been declared and units that were previously
providing CR are then dispatched higher to balance the increased load, does that constitute deploying
CR? What evidence does the RE provide? 3) Increased customer costs absent a demonstrated reliability
need as BA’s are incented to purchase additional contingency reserves beyond that needed to recover
from the loss of MSSC.4) Increased frequency variation as BA’s are incented to change generation
dispatch at the top of each hour to meet the R2 commodity obligation.5) Increased SOL & IROL
exceedance durations as BA’s are reluctant to deploy reserves to mitigate.6) As stated above, this
standard creates a compliance trap for System Operators who may have to choose between activating
reserves and shedding load for non-Reportable events OR following Reliability Directives under IRO-001
and maintaining reserves under BAL-002 R2.7) An increase in BAAL excursion minutes & frequency
variation as BA’s are discouraged from activating reserves for non-reportable events that are having an
adverse impact on system frequency. 8) Provides a disincentive for a BA to assist its neighbor when a
formal RSG Agreement is not in effect.9) The Severe VSL omits the “from a Reportable Balancing
ContŝŶŐĞŶĐLJǀĞŶƚ͟ůĂŶŐƵĂŐĞƚŚĂƚŝƐŝŶĐůƵĚĞĚŝŶƚŚĞ>ŽǁĞƌ͕DŽĚĞƌĂƚĞ͕Θ,ŝŐŚs^>Ɛ͘tĞďĞůŝĞǀĞƚŚŝƐ

omission was an oversight.10) The Background Document states on page 4 that “BAAL also ensures the
Responsible Entity balances resources and demand for events of less magnitude than a Reportable
Balancing Contingency” while R2 discourages the System Operator from using one of the important
tools for accomplishing that task; Contingency Reserves.11) The Background Document states on page 5
that “FERC Order 693 (at 355) directed entities to include a Requirement that measures response for
any event or contingency that causes a frequency deviation”. Order 693 (at P355) directs the ERO to
“define a significant deviation and a reportable event”. This misstatement in the Background Document
is significant and should be corrected.12) The Background Document states on page 6 that “the drafting
team elected to allow the Responsible Entity to use its Contingency Reserve while in a declared Energy
Emergency Alert 2 or Energy Emergency Alert 3”. This statement is inconsistent with the current
posting.13) The Background Document (Attachment 1) contains a series of box plots for each
Interconnection labeled “Frequency Events Loss MW Statistics”. a. The SDT should include a summary of
what this data represents, including event threshold criteria used to determine the sample. b. The data
appears to show loss of generation and loss of load events in the same samples. If the intent is to show
statistical correlation between the MW size of an event and magnitude of frequency deviation then loss
of generation and loss of load events should be separated. c. Last step in example on Page 22 of the
redline version, the -200 MW appears to be incorrect. The required ACE Recovery should be -600 MW.
The comments expressed herein represent a consensus of the views of the above-named members of
the SERC OC Review Group only and should not be construed as the position of SERC Reliability
Corporation, its board, or its officers.

Dean Fox/Consumers Energy
Although the standard does not directly affect Consumers Energy, after reviewing the purposed
standard and comments, I feel the intended goal to eliminate the ambiguities and questions associated
with the existing standard has not been met. The new definitions and standard language confuse and
complicate the issues.

Standards Announcement Reminder

Project 2010-14.1 Phase 1 of Balancing Authority
Reliability-based Controls
BAL-002-2
Additional Ballot and Non-Binding Poll Open through March 16, 2015
Now Available

An additional ballot for BAL-002-2 – Contingency Reserve for Recovery from Balancing Contingency
Event and a non-binding poll of the Associated Violation Risk Factors and Violation Severity Levels are
open through 8 p.m. Eastern, Monday, March 16, 2015.
Balloting – Legacy System

Members of the ballot pools associated with this project may log in and submit their vote for the
standard and non-binding poll by clicking here.
Note: If a member cast a vote in the previous ballot, that vote will not carry over to this additional
ballot. It is the responsibility of the registered voter in the ballot pool to cast a vote again in this ballot.
To ensure a quorum is reached, if you do not want to vote affirmative or negative, cast an abstention.
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 standard
and post it for an additional ballot. If the comments do not show the need for significant revisions, the
standard will proceed to a final ballot.
For more information on the Standards Development Process, refer to the Standard Processes Manual.
For more information or assistance, contact 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 2010-14.1 Phase 1 of Balancing Authority Reliabilitybased Controls: Reserves - BAL-002-2
Formal Comment Period Open through March 16, 2015
Now Available

A 45-day formal comment period for BAL-002-2 – Contingency Reserve for Recovery from Balancing
Contingency Event is open through 8 p.m. Eastern on Monday, March 16, 2015.
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 Arielle Cunningham. An off-line, unofficial copy of the comment form
is posted on the project page.
Next Steps

An additional ballot and non-binding poll of the associated Violation Risk Factors and Violation
Severity Levels will be conducted March 6 – March 16, 2015.
For more information on the Standards Development Process, please refer to the Standard
Processes Manual.

For more information or assistance, please contact Darrel Richardson, Standards Developer, or at 609-6131848.
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 2010-14.1 Phase 1 of Balancing Authority
Reliability-based Controls
BAL-002-2
Additional Ballot and Non-binding Poll Results
Now Available

AnadditionalballotforBALͲ002Ͳ2–DisturbanceControlStandard–ContingencyReserveforRecovery
fromaBalancingContingencyEventandanonͲbindingpolloftheassociatedViolationRiskFactorsand
ViolationSeverityLevelsconcludedat8p.m.Eastern,Wednesday,March18,2015.


Thestandardachievedaquorumbutdidnotreceivesufficientaffirmativevotesforapproval.Voting
statisticsarelistedbelow,andtheBallotResultspageprovidesalinktothedetailedresultsfortheballot.

Ballot

NonͲBindingPoll

Quorum/Approval

Quorum/SupportiveOpinions

77.29%/59.83%

75.86%/70.93%




Backgroundinformationforthisprojectcanbefoundontheprojectpage.
Next Steps

Thedraftingteamwillconsiderallcommentsreceivedduringtheformalcommentperiod,make
revisionstothestandardandpostitforanadditionalballot.
FormoreinformationontheStandardsDevelopmentProcess,refertotheStandardProcessesManual.
Formoreinformationorassistance,contactSeniorStandardsDeveloper,DarrelRichardson(viaemail),orat
(609)613Ͳ1848.
NorthAmericanElectricReliabilityCorporation
3353PeachtreeRd,NE
Suite600,NorthTower
Atlanta,GA30326
404Ͳ446Ͳ2560|www.nerc.com


NERC Standards

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Ballot Results

Ballot Name: Project 2010-14.1 BARC BAL-002-2
-Ballot Pools
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Ballot Period: 3/6/2015 - 3/18/2015
Ballot Type: $IILUPDWLYH
Total # Votes: 262
Total Ballot Pool: 339
Quorum: 77.29 % The Quorum has been reached

Home Page

Weighted Segment
59.83 %
Vote:
Ballot Results: The Ballot has Closed
Summary of Ballot Results

Affirmative

Negative

Negative
Vote
Ballot Segment
#
#
No
without a
Segment Pool
Weight Votes Fraction Votes Fraction Comment Abstain Vote
1Segment
1
2Segment
2
3Segment
3
4Segment
4
5Segment
5
6Segment
6
7Segment
7
8Segment
8
9Segment
9

89

1

43

0.729

16

0.271

0

13

17

10

0.8

2

0.2

6

0.6

0

1

1

75

1

31

0.646

17

0.354

0

12

15

23

1

8

0.533

7

0.467

0

5

3

71

1

32

0.727

12

0.273

0

10

17

53

1

20

0.714

8

0.286

0

8

17

2

0

0

0

0

0

0

0

2

5

0.2

1

0.1

1

0.1

0

1

2

3

0.1

1

0.1

0

0

0

0

2

https://standards.nerc.net/BallotResults.aspx?BallotGUID=7433b062-fbaa-4a77-8270-62fc8813d237[3/27/2015 2:59:57 PM]

NERC Standards
10 Segment
10
Totals

8

0.5

2

0.2

3

0.3

0

2

1

339

6.6

140

3.949

70

2.651

0

52

77

Individual Ballot Pool Results

Ballot
Segment
1
1
1
1
1
1
1
1
1
1
1

Organization

Member

1
1
1

Ameren Services
American Electric Power
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Austin Energy
Balancing Authority of Northern California
Baltimore Gas & Electric Company
BC Hydro and Power Authority
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
Central Electric Power Cooperative
City of Tacoma, Department of Public Utilities,
Light Division, dba Tacoma Power
City of Tallahassee
Clark Public Utilities
Colorado Springs Utilities

1

Consolidated Edison Co. of New York

Christopher L de Graffenried

1

CPS Energy

Richard Castrejana

1

Eric Scott
Paul B Johnson
Robert Smith
John Bussman
James Armke
Kevin Smith
Christopher J Scanlon
Patricia Robertson
Donald S. Watkins
Tony Kroskey
Michael B Bax

Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative

Chang G Choi

Affirmative

Daniel S Langston
Jack Stamper
Paul Morland

Affirmative
Affirmative
Affirmative

Affirmative
Abstain

Negative

Dairyland Power Coop.

Robert W. Roddy

Negative

1
1

Dayton Power & Light Co.
Dominion Virginia Power

Hertzel Shamash
Michael S Crowley

Abstain

Duke Energy Carolina

Doug E Hils

1
1

El Paso Electric Company
Entergy Transmission

Dennis Malone
Oliver A Burke

1

FirstEnergy Corp.

William J Smith

1
1

Florida Power & Light Co.
Gainesville Regional Utilities

Mike O'Neil
Richard Bachmeier

1

Great River Energy

Gordon Pietsch

1

Hydro One Networks, Inc.

Ajay Garg

1

Hydro-Quebec TransEnergie

1

Idaho Power Company
Molly Devine
International Transmission Company Holdings
Michael Moltane
Corp
JDRJC Associates
Jim D Cyrulewski
KAMO Electric Cooperative
Walter Kenyon
Kansas City Power & Light Co.
Jennifer Flandermeyer

1
1
1
1

1

Lakeland Electric

Martin Boisvert

Larry E Watt

https://standards.nerc.net/BallotResults.aspx?BallotGUID=7433b062-fbaa-4a77-8270-62fc8813d237[3/27/2015 2:59:57 PM]

COMMENT
RECEIVED

Affirmative

1

1

NERC
Notes

Negative

SUPPORTS
THIRD
PARTY
COMMENTS (MISO)

SUPPORTS
THIRD
PARTY
COMMENTS (Duke
Energy)

Abstain
Affirmative

Negative

SUPPORTS
THIRD
PARTY
COMMENTS (PJM
Comments)

Affirmative

Negative

SUPPORTS
THIRD
PARTY
COMMENTS (NSRF)

Abstain

Negative

SUPPORTS
THIRD
PARTY
COMMENTS (NPCC)

Affirmative
Abstain
Affirmative
Affirmative

Negative

SUPPORTS
THIRD
PARTY

NERC Standards
COMMENTS (FMPA)
1
1
1
1
1
1
1
1
1
1

Lincoln Electric System
Long Island Power Authority
Los Angeles Department of Water & Power
Lower Colorado River Authority
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
N.W. Electric Power Cooperative, Inc.

Doug Bantam
Robert Ganley
John Burnett
Martyn Turner
William Price
Nazra S Gladu
Danny Dees
Terry Harbour
Andrew J Kurriger
Mark Ramsey

Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

1

National Grid USA

Michael Jones

1

Nebraska Public Power District

Cole C Brodine

1

New Brunswick Power Transmission
Corporation

Randy MacDonald

Negative

1

New York Power Authority

Bruce Metruck

Negative

1
1
1

Northeast Missouri Electric Power Cooperative Kevin White
Northern Indiana Public Service Co.
Julaine Dyke
Ohio Valley Electric Corp.
Robert Mattey

1

Oklahoma Gas and Electric Co.

Terri Pyle

1
1
1
1
1
1
1

Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
Platte River Power Authority
Portland General Electric Co.

Doug Peterchuck
Jen Fiegel
Brad Chase
Daryl Hanson
Bangalore Vijayraghavan
John C. Collins
John T Walker

1

Potomac Electric Power Co.

David Thorne

1

PowerSouth Energy Cooperative

Larry D Avery

Negative

Negative

Affirmative
Affirmative

Negative

SUPPORTS
THIRD
PARTY
COMMENTS (SRC)
SUPPORTS
THIRD
PARTY
COMMENTS (Comments
submitted on
behalf of PPL
NERC
Registered
Affiliates.)

Brenda L Truhe

Negative

1

Public Service Company of New Mexico

Laurie Williams

Affirmative

Kenneth D. Brown

1
1

Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.

Denise M Lietz
John C. Allen

https://standards.nerc.net/BallotResults.aspx?BallotGUID=7433b062-fbaa-4a77-8270-62fc8813d237[3/27/2015 2:59:57 PM]

SUPPORTS
THIRD
PARTY
COMMENTS (SPP Group
Comments)

Abstain
Abstain
Affirmative

PPL Electric Utilities Corp.

Public Service Electric and Gas Co.

SUPPORTS
THIRD
PARTY
COMMENTS NPCC RSC
SUPPORTS
THIRD
PARTY
COMMENTS (Support
NPCC
comments)

Affirmative
Abstain

1

1

SUPPORTS
THIRD
PARTY
COMMENTS (National
Grid
supports
NPCC's
comments.)

Negative

Affirmative

SUPPORTS
THIRD
PARTY
COMMENTS ISO/RTO
Council

NERC Standards
1
1
1
1
1
1
1
1
1
1
1

Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
Santee Cooper
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southern California Edison Company
Southern Company Services, Inc.

Tim Kelley
Robert Kondziolka
Will Speer
Terry L Blackwell
Pawel Krupa
Denise Stevens
Richard Salgo
Long T Duong
Tom Hanzlik
Steven Mavis
Robert A. Schaffeld

1

Southern Illinois Power Coop.

William Hutchison

1
1
1
1
1
1

Southwest Transmission Cooperative, Inc.
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.

John Shaver
Noman Lee Williams
Beth Young
Howell D Scott
Tracy Sliman
John Tolo

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

Negative

Affirmative

Affirmative
Abstain
Affirmative

1

United Illuminating Co.

Jonathan Appelbaum

1
1
1
2

Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator

2

BC Hydro

2

California ISO

Allen Klassen
Lloyd A Linke
Gregory L Pieper
Ken A Gardner
Venkataramakrishnan
Vinnakota
Rich Vine

2

Electric Reliability Council of Texas, Inc.

Cheryl Moseley

Negative

2

ISO New England, Inc.

Kathleen Goodman

Negative

2

Midwest ISO, Inc.

Marie Knox

Negative

2

New Brunswick System Operator

Alden Briggs

Negative

Affirmative
Abstain

New York Independent System Operator

Gregory Campoli

Negative

2

PJM Interconnection, L.L.C.

stephanie monzon

Negative

2

Southwest Power Pool, Inc.

Charles H. Yeung

Negative

3
3
3
3
3
3
3
3
3
3
3

AEP
Alabama Power Company
Ameren Services
APS
Associated Electric Cooperative, Inc.
Atlantic City Electric Company
Avista Corp.
BC Hydro and Power Authority
Bonneville Power Administration
Central Electric Power Cooperative
City of Austin dba Austin Energy

Michael E Deloach
Robert S Moore
Mark Peters
Steven Norris
Chris W Bolick
NICOLE BUCKMAN
Scott J Kinney
Pat G. Harrington
Rebecca Berdahl
Adam M Weber
Andrew Gallo

Abstain
Affirmative
Affirmative

City of Bartow, Florida

Matt Culverhouse

https://standards.nerc.net/BallotResults.aspx?BallotGUID=7433b062-fbaa-4a77-8270-62fc8813d237[3/27/2015 2:59:57 PM]

SUPPORTS
THIRD
PARTY
COMMENTS (NPCC)

Affirmative
Affirmative
Affirmative

2

3

SUPPORTS
THIRD
PARTY
COMMENTS (ACES)

COMMENT
RECEIVED
COMMENT
RECEIVED
SUPPORTS
THIRD
PARTY
COMMENTS (ISO/RTO
SRC and
MRO NSRF)
SUPPORTS
THIRD
PARTY
COMMENTS (IRC/SRC
and NPCC
RSC)
COMMENT
RECEIVED
COMMENT
RECEIVED

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

Negative

SUPPORTS
THIRD
PARTY
COMMENTS (Duke

NERC Standards
Energy)
3
3
3
3

City of Redding
City of Tallahassee
Colorado Springs Utilities
ComEd

Bill Hughes
Bill R Fowler
Charles Morgan
John Bee

Affirmative

3

Consolidated Edison Co. of New York

Peter T Yost

Negative

3

Consumers Energy

Richard Blumenstock

Negative

3
3
3
3
3
3

CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources, Inc.
El Paso Electric Company
Entergy

Jose Escamilla
Michael R. Mayer
Kent Kujala
Connie B Lowe
Tracy Van Slyke
Joel T Plessinger

Affirmative
Abstain

Abstain
Abstain
Affirmative

3

FirstEnergy Corp.

Cindy E Stewart

Negative

3

Florida Municipal Power Agency

Joe McKinney

Negative

3

Florida Power Corporation

Lee Schuster

Negative

3

Gainesville Regional Utilities

Kenneth Simmons

Negative

3

Great River Energy

Brian Glover

Negative

3
3
3
3
3

Hydro One Networks, Inc.
Imperial Irrigation District
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.

David Kiguel
Jesus S. Alcaraz
Garry Baker
Theodore J Hilmes
Charles Locke

3

Kissimmee Utility Authority

Gregory D Woessner

3
3

Lakeland Electric
Lincoln Electric System

Mace D Hunter
Jason Fortik

3

Louisville Gas and Electric Co.

Charles A. Freibert

3
3
3
3

M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
Modesto Irrigation District

Stephen D Pogue
Greg C. Parent
Roger Brand
Jack W Savage

SUPPORTS
THIRD
PARTY
COMMENTS PJM
COMMENT
RECEIVED
SUPPORTS
THIRD
PARTY
COMMENTS (Duke
Energy)
SUPPORTS
THIRD
PARTY
COMMENTS FMPA
SUPPORTS
THIRD
PARTY
COMMENTS (GRE
supports the
NSRF
comments.)

Abstain
Affirmative
Affirmative

Negative

SUPPORTS
THIRD
PARTY
COMMENTS (Duke
Energy)

Abstain

Negative

SUPPORTS
THIRD
PARTY
COMMENTS (PPL NERC
Registered
Affiliates)

Affirmative
Affirmative
Affirmative

3

Muscatine Power & Water

John S Bos

Negative

3

National Grid USA

Brian E Shanahan

Negative

https://standards.nerc.net/BallotResults.aspx?BallotGUID=7433b062-fbaa-4a77-8270-62fc8813d237[3/27/2015 2:59:57 PM]

COMMENT
RECEIVED
COMMENT
RECEIVED

SUPPORTS
THIRD
PARTY
COMMENTS NSRF
SUPPORTS
THIRD
PARTY
COMMENTS (NPCC RSC)

NERC Standards
3

Nebraska Public Power District

Tony Eddleman

3

New York Power Authority

David R Rivera

3
3

Northeast Missouri Electric Power Cooperative Skyler Wiegmann
NW Electric Power Cooperative, Inc.
David McDowell

3

Oklahoma Gas and Electric Co.

Donald Hargrove

3
3
3
3
3
3
3
3

Omaha Public Power District
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Portland General Electric Co.

Blaine R. Dinwiddie
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Thomas G Ward

Abstain

Negative

Affirmative

Negative

Affirmative
Affirmative
Abstain

Potomac Electric Power Co.

Mark Yerger

Negative

3

Public Service Electric and Gas Co.

Jeffrey Mueller

Negative

3
3
3
3
3
3
3
3
3
3
3
3
3
3

Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Sho-Me Power Electric Cooperative
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Westar Energy

Erin Apperson
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Jeff L Neas
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L. Donahey
Ian S Grant
Janelle Marriott
Bo Jones

Wisconsin Electric Power Marketing

James R Keller

3
4
4
4
4
4

Xcel Energy, Inc.
Self
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
City of Austin dba Austin Energy

Michael Ibold
Herb Schrayshuen
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Reza Ebrahimian

4

City of New Smyrna Beach Utilities
Commission

Tim Beyrle

4
4

City of Redding
City Utilities of Springfield, Missouri

Nicholas Zettel
John Allen

4

Consumers Energy Company

Tracy Goble

4

Flathead Electric Cooperative

Russ Schneider

4

Florida Municipal Power Agency

Frank Gaffney

https://standards.nerc.net/BallotResults.aspx?BallotGUID=7433b062-fbaa-4a77-8270-62fc8813d237[3/27/2015 2:59:57 PM]

SUPPORTS
THIRD
PARTY
COMMENTS (SPP Group
Comments)

Abstain
Affirmative
Abstain

3

3

SUPPORTS
THIRD
PARTY
COMMENTS (NPCC’s CO1 and CO-08
working
groups)

SUPPORTS
THIRD
PARTY
COMMENTS (SRC)
SUPPORTS
THIRD
PARTY
COMMENTS (ISO/RTO
Council)

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain

Negative

SUPPORTS
THIRD
PARTY
COMMENTS (MISO)

Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative

Negative

SUPPORTS
THIRD
PARTY
COMMENTS FMPA

Affirmative
Abstain
Negative

COMMENT
RECEIVED

Abstain
Negative

COMMENT
RECEIVED

NERC Standards
4

Georgia System Operations Corporation

Guy Andrews

4

Madison Gas and Electric Co.

Joseph DePoorter

4

Modesto Irrigation District

Spencer Tacke

4

Ohio Edison Company

4

Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
Tacoma Public Utilities

4
4
4
4
4

Douglas Hohlbaugh

Abstain

Negative

SUPPORTS
THIRD
PARTY
COMMENTS (MRO NSRF)

Negative

SUPPORTS
THIRD
PARTY
COMMENTS (FE supports
PJM
Comments)

Henry E. LuBean
John D Martinsen

Affirmative

Mike Ramirez
Hao Li
Steven R Wallace
Keith Morisette

Affirmative
Affirmative
Affirmative

4

Utility Services, Inc.

Brian Evans-Mongeon

Negative

4

Wisconsin Energy Corp.

Anthony P Jankowski

Negative

5
5
5
5
5

AEP Service Corp.
Brock Ondayko
Amerenue
Sam Dwyer
Arizona Public Service Co.
Scott Takinen
Associated Electric Cooperative, Inc.
Matthew Pacobit
BC Hydro and Power Authority
Clement Ma
Boise-Kuna Irrigation District/dba Lucky peak
Mike D Kukla
power plant project
Bonneville Power Administration
Francis J. Halpin
Brazos Electric Power Cooperative, Inc.
Shari Heino
City of Austin dba Austin Energy
Jeanie Doty
City of Redding
Paul A. Cummings
City of Tallahassee
Karen Webb
City Water, Light & Power of Springfield
Steve Rose
Colorado Springs Utilities
Michael Shultz
Consolidated Edison Co. of New York
Wilket (Jack) Ng

5
5
5
5
5
5
5
5
5

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

5

Consumers Energy Company

David C Greyerbiehl

Negative

5

Dairyland Power Coop.

Tommy Drea

Negative

5
5
5
5
5

Dominion Resources, Inc.
Duke Energy
Electric Power Supply Association
Entergy Services, Inc.
Exelon Nuclear

Mike Garton
Dale Q Goodwine
John R Cashin
Tracey Stubbs
Mark F Draper

Affirmative
Abstain

FirstEnergy Solutions

Kenneth Dresner

Negative

5

Florida Municipal Power Agency

David Schumann

Negative

5

Gainesville Regional Utilities

Karen C Alford

Great River Energy

Preston L Walsh

https://standards.nerc.net/BallotResults.aspx?BallotGUID=7433b062-fbaa-4a77-8270-62fc8813d237[3/27/2015 2:59:57 PM]

SUPPORTS
THIRD
PARTY
COMMENTS (Dean Fox)
SUPPORTS
THIRD
PARTY
COMMENTS (MISO)

Abstain

5

5

SUPPORTS
THIRD
PARTY
COMMENTS (NPCC)
SUPPORTS
THIRD
PARTY
COMMENTS (MISO)

Negative

SUPPORTS
THIRD
PARTY
COMMENTS PJM
Comments
COMMENT
RECEIVED
SUPPORTS
THIRD
PARTY
COMMENTS -

NERC Standards
(NSRF)
5
5
5

Imperial Irrigation District
JEA
Kansas City Power & Light Co.

Marcela Y Caballero
John J Babik
Brett Holland

Affirmative

5

Lakeland Electric

James M Howard

5
5
5

Lincoln Electric System
Los Angeles Department of Water & Power
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.

Dennis Florom
Kenneth Silver
S N Fernando

Affirmative
Affirmative

David Gordon

Abstain

5
5
5

Steven Grego
Neil D Hammer

5

Muscatine Power & Water

Mike Avesing

5

Nebraska Public Power District

Don Schmit

5

New York Power Authority

Wayne Sipperly

5
5
5

NextEra Energy
Northern Indiana Public Service Co.
Oglethorpe Power Corporation

Allen D Schriver
William O. Thompson
Bernard Johnson

5

Oklahoma Gas and Electric Co.

Henry L Staples

5
5
5
5
5
5

Omaha Public Power District
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PowerSouth Energy Cooperative

Mahmood Z. Safi
Richard K Kinas
Bonnie Marino-Blair
Roland Thiel
Matt E. Jastram
Tim Hattaway

Negative

Affirmative

Negative

Negative

SUPPORTS
THIRD
PARTY
COMMENTS (NPCC)

Negative

SUPPORTS
THIRD
PARTY
COMMENTS (SPP Group
Comments)

Abstain
Affirmative
Affirmative
Affirmative
Affirmative

PPL Generation LLC

Annette M Bannon

Negative

5

PSEG Fossil LLC

Tim Kucey

Negative

5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5

Public Utility District No. 2 of Grant County,
Washington
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southern California Edison Company
Southern Company Generation
Tacoma Power
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers

Michiko Sell

Affirmative

Lynda Kupfer
Susan Gill-Zobitz
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Edward Magic
Denise Yaffe
William D Shultz
Chris Mattson
RJames Rocha
Scott Helyer
David Thompson
Mark Stein
Melissa Kurtz

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain

https://standards.nerc.net/BallotResults.aspx?BallotGUID=7433b062-fbaa-4a77-8270-62fc8813d237[3/27/2015 2:59:57 PM]

SUPPORTS
THIRD
PARTY
COMMENTS (NSRF)

Abstain

5

5

SUPPORTS
THIRD
PARTY
COMMENTS (DEF)

Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain

SUPPORTS
THIRD
PARTY
COMMENTS (PPL NERC
Registered
Affiliates)
SUPPORTS
THIRD
PARTY
COMMENTS (ISO/RTO
Council)

NERC Standards
5
5

U.S. Bureau of Reclamation
Westar Energy

Martin Bauer
Bryan Taggart

5

Wisconsin Electric Power Co.

Linda Horn

5
6
6
6
6

Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
APS
Associated Electric Cooperative, Inc.

Liam Noailles
Edward P. Cox
Jennifer Richardson
Randy A. Young
Brian Ackermann

Affirmative
Abstain
Affirmative
Affirmative

6

Bonneville Power Administration

Brenda S. Anderson

Affirmative

6
6
6
6

City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities

Lisa Martin
Marvin Briggs
Robert Hirchak
Shannon Fair

Affirmative
Affirmative

6

Con Edison Company of New York

David Balban

6
6

Constellation Energy Commodities Group
Dominion Resources, Inc.

David J Carlson
Louis S. Slade

6

Duke Energy

Greg Cecil

6

Entergy Services, Inc.

Terri F Benoit

Negative

Negative

Negative

Kevin Querry

Negative

6

Florida Municipal Power Agency

Richard L. Montgomery

Negative

6
6
6
6
6

Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.

Thomas Washburn
Silvia P Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer

Paul Shipps

6
6
6
6
6
6

Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Energy
Manitoba Hydro
Modesto Irrigation District
Muscatine Power & Water

Eric Ruskamp
Brad Packer
Brenda Hampton
Blair Mukanik
James McFall
John Stolley

6

New York Power Authority

Saul Rojas

6
6
6
6
6
6
6

Northern Indiana Public Service Co.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
Power Generation Services, Inc.
Powerex Corp.

Joseph O'Brien
Douglas Collins
Kelly Cumiskey
Carol Ballantine
Ty Bettis
Stephen C Knapp
Daniel W. O'Hearn

6

PPL EnergyPlus LLC

Elizabeth Davis

https://standards.nerc.net/BallotResults.aspx?BallotGUID=7433b062-fbaa-4a77-8270-62fc8813d237[3/27/2015 2:59:57 PM]

COMMENT
RECEIVED

Abstain
Abstain

FirstEnergy Solutions

Lakeland Electric

NO COMMENT
RECEIVED

Affirmative

6

6

SUPPORTS
THIRD
PARTY
COMMENTS (MISO)

SUPPORTS
THIRD
PARTY
COMMENTS (Duke
Energy)
SUPPORTS
THIRD
PARTY
COMMENTS (FE supports
PJM
comments)
COMMENT
RECEIVED

Affirmative

Negative

SUPPORTS
THIRD
PARTY
COMMENTS (FMPA)

Abstain
Affirmative
Abstain
Affirmative

Negative

SUPPORTS
THIRD
PARTY
COMMENTS (NPCC’s CO1 and CO-08
working
groups)

Abstain
Abstain
Affirmative
Affirmative

Negative

SUPPORTS
THIRD
PARTY
COMMENTS -

NERC Standards

6

PSEG Energy Resources & Trade LLC

Peter Dolan

6
6
6
6
6
6
6
6

Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
Southern California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
EnerVision, Inc.
Steel Manufacturers Association

Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
Kenn Backholm
Lujuanna Medina

Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative

John J. Ciza

Affirmative

Michael C Hill
Benjamin F Smith II
Marjorie S Parsons
Grant L Wilkerson

Affirmative

6
6
6
6
6
6
6
7
7
8

8

8
8
8
9
9
9
10

Affirmative

Peter H Kinney
David F Lemmons
Thomas W Siegrist
James Brew
Robert Blohm

Roger C Zaklukiewicz

Debra R Warner
Energy Mark, Inc.
Volkmann Consulting, Inc.
Commonwealth of Massachusetts Department
of Public Utilities
Gainesville Regional Utilities
National Association of Regulatory Utility
Commissioners
Florida Reliability Coordinating Council

Negative

(PPL NERC
Registered
Affiliates)
SUPPORTS
THIRD
PARTY
COMMENTS ISO/RTO
Council

Affirmative

Negative

Debra R Warner
Howard F. Illian
Terry Volkmann

Affirmative

Donald Nelson

Affirmative

SUPPORTS
THIRD
PARTY
COMMENTS (NPCC)

Abstain

Norman Harryhill
Diane J. Barney
Linda D Campbell

10

Midwest Reliability Organization

Russel Mountjoy

10

New York State Reliability Council

Alan Adamson

10

Northeast Power Coordinating Council

Guy V. Zito

10

ReliabilityFirst Corporation

Anthony E Jablonski

10

SERC Reliability Corporation

Carter B Edge

10
10

Texas Reliability Entity, Inc.
Western Electricity Coordinating Council

Donald G Jones
Steven L. Rueckert

Abstain

Negative

SUPPORTS
THIRD
PARTY
COMMENTS (MRO NSRF)

Negative

COMMENT
RECEIVED

Abstain
Negative
Affirmative
Affirmative

Legal and Privacy : 404.446.2560 voice : 404.467.0474 fax : 3353 Peachtree Road, N.E. : Suite 600, North Tower : Atlanta, GA 30326
Washington Office: 1325 G Street, N.W. : Suite 600 : Washington, DC 20005-3801

https://standards.nerc.net/BallotResults.aspx?BallotGUID=7433b062-fbaa-4a77-8270-62fc8813d237[3/27/2015 2:59:57 PM]

COMMENT
RECEIVED

NERC Standards
Copyright © 2015 by the North American Electric Reliability Corporation. : All rights reserved.
A New Jersey Nonprofit Corporation

https://standards.nerc.net/BallotResults.aspx?BallotGUID=7433b062-fbaa-4a77-8270-62fc8813d237[3/27/2015 2:59:57 PM]

Non-Binding Poll Results

Project 2010-14.1 Phase 1 of Balancing Authority
Reliability-based Controls
BAL-002-2
Non-Binding Poll Results

Non-Binding Poll
Project 2010-14.1 BARC BAL-002-2
Name:
Poll Period: 3/6/2015 - 3/18/2015
Total # Opinions: 242
Total Ballot Pool: 319
75.86% of those who registered to participate provided an opinion or an
Summaray Results: abstention; 70.93% of those who provided an opinion indicated support for
the VRFs and VSLs.
Individual Ballot Pool Results

Segment

Organization

Member

1
1

Ameren Services
American Electric Power

Eric Scott
Paul B Johnson

1

Arizona Public Service Co.

Robert Smith

1
1
1
1
1
1
1

Associated Electric Cooperative, Inc.
John Bussman
Austin Energy
James Armke
Balancing Authority of Northern California Kevin Smith
BC Hydro and Power Authority
Patricia Robertson
Bonneville Power Administration
Donald S. Watkins
Brazos Electric Power Cooperative, Inc.
Tony Kroskey
Central Electric Power Cooperative
Michael B Bax
City of Tacoma, Department of Public
Chang G Choi
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
Daniel S Langston
Clark Public Utilities
Jack Stamper
Colorado Springs Utilities
Paul Morland
Christopher L de
Consolidated Edison Co. of New York
Graffenried
CPS Energy
Richard Castrejana
Dairyland Power Coop.
Robert W. Roddy
Dominion Virginia Power
Michael S Crowley

1
1
1
1
1
1
1
1

Opinions

NERC
Notes

Abstain
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Abstain

COMMENT
RECEIVED

1

Duke Energy Carolina

Doug E Hils

1
1

El Paso Electric Company
Entergy Transmission

Dennis Malone
Oliver A Burke

1

FirstEnergy Corp.

William J Smith

1

Florida Power & Light Co.

Mike O'Neil

1

Gainesville Regional Utilities

Richard Bachmeier

1

Great River Energy

Gordon Pietsch

1

Hydro One Networks, Inc.

Ajay Garg

1

Hydro-Quebec TransEnergie

Martin Boisvert

1

Molly Devine

1
1

Idaho Power Company
International Transmission Company
Holdings Corp
JDRJC Associates
KAMO Electric Cooperative

1

Kansas City Power & Light Co.

Jennifer Flandermeyer

1

Abstain
Affirmative

Negative

Negative

Negative

Affirmative
Affirmative

1

Lincoln Electric System

Doug Bantam

1
1
1
1
1
1
1

Long Island Power Authority
Robert Ganley
Los Angeles Department of Water & Power John Burnett
Lower Colorado River Authority
Martyn Turner
M & A Electric Power Cooperative
William Price
Manitoba Hydro
Nazra S Gladu
MEAG Power
Danny Dees
MidAmerican Energy Co.
Terry Harbour

1

Muscatine Power & Water

Andrew J Kurriger

1

N.W. Electric Power Cooperative, Inc.

Mark Ramsey

1

National Grid USA

Michael Jones

1

Nebraska Public Power District

Cole C Brodine

SUPPORTS
THIRD PARTY
COMMENTS (NPCC)

Affirmative

Jim D Cyrulewski
Walter Kenyon

Larry E Watt

SUPPORTS
THIRD PARTY
COMMENTS (NSRF)

Abstain

Abstain

Lakeland Electric

SUPPORTS
THIRD PARTY
COMMENTS (PJM
Comments)

Affirmative

Michael Moltane

1

Non-Binding Poll Results
Project 2010-14.1 BAL-002-2 | March 2015

Negative

SUPPORTS
THIRD PARTY
COMMENTS (Duke Energy)

Negative

SUPPORTS
THIRD PARTY
COMMENTS (FMPA)

Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

Negative

SUPPORTS
THIRD PARTY
COMMENTS (National Grid
supports
NPCC's
comments.)

2

1

New Brunswick Power Transmission
Corporation

Randy MacDonald

Negative

1

New York Power Authority

Bruce Metruck

Negative

1

Northeast Missouri Electric Power
Cooperative
Northern Indiana Public Service Co.

1

Ohio Valley Electric Corp.

1

Kevin White

Affirmative

Julaine Dyke

Abstain

Robert Mattey

1

Oklahoma Gas and Electric Co.

Terri Pyle

1
1

Omaha Public Power District
Orlando Utilities Commission

Doug Peterchuck
Brad Chase

1

Otter Tail Power Company

Daryl Hanson

1

Pacific Gas and Electric Company

Bangalore Vijayraghavan

1
1

Platte River Power Authority
Portland General Electric Co.

John C. Collins
John T Walker

1

PowerSouth Energy Cooperative

Larry D Avery

1

PPL Electric Utilities Corp.

1

Public Service Company of New Mexico

Laurie Williams

1
1
1
1

Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project

Kenneth D. Brown
Denise M Lietz
Tim Kelley
Robert Kondziolka

Brenda L Truhe

1

San Diego Gas & Electric

Will Speer

1
1

Santee Cooper
Seattle City Light

Terry L Blackwell
Pawel Krupa

1

Sho-Me Power Electric Cooperative

Denise Stevens

1
1
1
1
1

Sierra Pacific Power Co.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southern California Edison Company
Southern Company Services, Inc.

Richard Salgo
Long T Duong
Tom Hanzlik
Steven Mavis
Robert A. Schaffeld

1

Southern Illinois Power Coop.

William Hutchison

Non-Binding Poll Results
Project 2010-14.1 BAL-002-2 | March 2015

SUPPORTS
THIRD PARTY
COMMENTS NPCC RSC
SUPPORTS
THIRD PARTY
COMMENTS (Supprts NPCC
Comments)

Negative

SUPPORTS
THIRD PARTY
COMMENTS (SPP Group
Comments)

Abstain
Affirmative

Abstain
Affirmative

Negative

SUPPORTS
THIRD PARTY
COMMENTS (Comments
submitted on
behalf of PPL
NERC
Registered
Affiliates.)

Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative

SUPPORTS
THIRD PARTY

3

COMMENTS (ACES)
1

Southwest Transmission Cooperative, Inc. John Shaver

1

Sunflower Electric Power Corporation

Noman Lee Williams

1

Tampa Electric Co.

Beth Young

1
1
1
1

Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.

Howell D Scott
Tracy Sliman
John Tolo
Jonathan Appelbaum

1

Westar Energy

Allen Klassen

1

Western Area Power Administration

Lloyd A Linke

1

Xcel Energy, Inc.

Gregory L Pieper

2

BC Hydro

2

California ISO

Venkataramakrishnan
Vinnakota
Rich Vine

2

Electric Reliability Council of Texas, Inc.

Cheryl Moseley

Negative

2

Midwest ISO, Inc.

Marie Knox

Negative

2

New Brunswick System Operator

Alden Briggs

2

New York Independent System Operator

Gregory Campoli

2

PJM Interconnection, L.L.C.

stephanie monzon

Negative

2
3
3
3

Southwest Power Pool, Inc.
AEP
Alabama Power Company
Ameren Services

Charles H. Yeung
Michael E Deloach
Robert S Moore
Mark Peters

Abstain
Abstain
Affirmative
Abstain

3

APS

Steven Norris

3
3
3
3
3
3
3

Associated Electric Cooperative, Inc.
Avista Corp.
BC Hydro and Power Authority
Bonneville Power Administration
Central Electric Power Cooperative
City of Austin dba Austin Energy
City of Redding

Chris W Bolick
Scott J Kinney
Pat G. Harrington
Rebecca Berdahl
Adam M Weber
Andrew Gallo
Bill Hughes

3

City of Tallahassee

Bill R Fowler

3

Colorado Springs Utilities

Charles Morgan

3

Consolidated Edison Co. of New York

Peter T Yost

Negative

3

Consumers Energy

Richard Blumenstock

Negative

3

CPS Energy

Jose Escamilla

3

Detroit Edison Company

Kent Kujala

3

Dominion Resources, Inc.

Connie B Lowe

Non-Binding Poll Results
Project 2010-14.1 BAL-002-2 | March 2015

Affirmative

Abstain
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Abstain
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (ISO/RTO SRC
and MRO
NSRF)

Abstain
COMMENT
RECEIVED

Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
COMMENT
RECEIVED
COMMENT
RECEIVED

Abstain

4

3
3

El Paso Electric Company
Entergy

Tracy Van Slyke
Joel T Plessinger

Abstain
Affirmative

3

FirstEnergy Corp.

Cindy E Stewart

Negative

3

Florida Municipal Power Agency

Joe McKinney

Negative

3

Florida Power Corporation

Lee Schuster

Negative

3

Gainesville Regional Utilities

Kenneth Simmons

Negative

3

Great River Energy

Brian Glover

Negative

3

Hydro One Networks, Inc.

David Kiguel

Abstain

3

Imperial Irrigation District

Jesus S. Alcaraz

3
3

JEA
KAMO Electric Cooperative

Garry Baker
Theodore J Hilmes

3

Kansas City Power & Light Co.

Charles Locke

3

Kissimmee Utility Authority

Gregory D Woessner

3

Lakeland Electric

Mace D Hunter

3

Lincoln Electric System

Jason Fortik

3

Louisville Gas and Electric Co.

Charles A. Freibert

3
3
3

M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power

Stephen D Pogue
Greg C. Parent
Roger Brand

3

Modesto Irrigation District

Jack W Savage

Affirmative
Affirmative

Negative

Affirmative
Affirmative
Affirmative

Muscatine Power & Water

John S Bos

Negative

3

National Grid USA

Brian E Shanahan

Negative

3

Nebraska Public Power District

Tony Eddleman

New York Power Authority

Non-Binding Poll Results
Project 2010-14.1 BAL-002-2 | March 2015

David R Rivera

SUPPORTS
THIRD PARTY
COMMENTS (Duke Energy)

Abstain

3

3

SUPPORTS
THIRD PARTY
COMMENTS PJM
Comments
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Duke Energy)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (GRE supports
the NSRF
comments.)

SUPPORTS
THIRD PARTY
COMMENTS NSRF
SUPPORTS
THIRD PARTY
COMMENTS (NPCC RSC)

Abstain

Negative

SUPPORTS
THIRD PARTY
COMMENTS (NPCC’s CO-1
and CO-08

5

working
groups)
3

Northeast Missouri Electric Power
Cooperative

Skyler Wiegmann

3

NW Electric Power Cooperative, Inc.

David McDowell

3

Oklahoma Gas and Electric Co.

Donald Hargrove

3
3
3

Omaha Public Power District
Orlando Utilities Commission
Owensboro Municipal Utilities

Blaine R. Dinwiddie
Ballard K Mutters
Thomas T Lyons

3

Pacific Gas and Electric Company

John H Hagen

3
3

PacifiCorp
Platte River Power Authority

Dan Zollner
Terry L Baker

3

PNM Resources

Michael Mertz

3
3
3
3
3
3
3
3

Portland General Electric Co.
Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.

Thomas G Ward
Jeffrey Mueller
Erin Apperson
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen

3

Sho-Me Power Electric Cooperative

Jeff L Neas

3
3
3

Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities

Mark Oens
Hubert C Young
Travis Metcalfe

3

Tampa Electric Co.

Ronald L. Donahey

3
3
3

Tennessee Valley Authority
Tri-State G & T Association, Inc.
Westar Energy

Ian S Grant
Janelle Marriott
Bo Jones

3

Wisconsin Electric Power Marketing

James R Keller

3
4
4
4
4
4

Michael Ibold
Herb Schrayshuen
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Reza Ebrahimian

4
4

Xcel Energy, Inc.
Self
Alliant Energy Corp. Services, Inc.
American Municipal Power
Blue Ridge Power Agency
City of Austin dba Austin Energy
City of New Smyrna Beach Utilities
Commission
City of Redding
City Utilities of Springfield, Missouri

4

Consumers Energy Company

Tracy Goble

4

Flathead Electric Cooperative

Russ Schneider

4

Non-Binding Poll Results
Project 2010-14.1 BAL-002-2 | March 2015

Tim Beyrle
Nicholas Zettel
John Allen

Affirmative

Negative

SUPPORTS
THIRD PARTY
COMMENTS (SPP Group
Comments)

Abstain
Abstain
Abstain
Affirmative
Abstain
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Negative

COMMENT
RECEIVED

Affirmative
Abstain
Negative

COMMENT
RECEIVED

Abstain

6

4

Florida Municipal Power Agency

Frank Gaffney

4
4

Georgia System Operations Corporation
Madison Gas and Electric Co.

Guy Andrews
Joseph DePoorter

4

Modesto Irrigation District

Spencer Tacke

4

Ohio Edison Company

Douglas Hohlbaugh

Negative
Abstain
Abstain

Negative

John D Martinsen

Affirmative

4
4

Public Utility District No. 1 of Douglas
County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light

Mike Ramirez
Hao Li

Affirmative
Affirmative

4

Seminole Electric Cooperative, Inc.

Steven R Wallace

4
4

Tacoma Public Utilities
Utility Services, Inc.

Keith Morisette
Brian Evans-Mongeon

4
4

Anthony P Jankowski

Affirmative
Abstain

Wisconsin Energy Corp.

5

AEP Service Corp.

Brock Ondayko

5
5
5
5

Sam Dwyer
Scott Takinen
Matthew Pacobit
Clement Ma

Abstain
Affirmative
Affirmative
Affirmative

Mike D Kukla

Affirmative

5
5
5
5
5
5
5

Amerenue
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
BC Hydro and Power Authority
Boise-Kuna Irrigation District/dba Lucky
peak power plant project
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
City of Austin dba Austin Energy
City of Redding
City of Tallahassee
City Water, Light & Power of Springfield
Colorado Springs Utilities

Francis J. Halpin
Shari Heino
Jeanie Doty
Paul A. Cummings
Karen Webb
Steve Rose
Michael Shultz

Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

5

Consolidated Edison Co. of New York

Wilket (Jack) Ng

Negative

5

Consumers Energy Company

David C Greyerbiehl

Negative

5

Dairyland Power Coop.

Tommy Drea

Negative

5

Dominion Resources, Inc.

Mike Garton

5

Duke Energy

Dale Q Goodwine

Non-Binding Poll Results
Project 2010-14.1 BAL-002-2 | March 2015

SUPPORTS
THIRD PARTY
COMMENTS (FE supports
PJM
comments)

Henry E. LuBean

4

5

COMMENT
RECEIVED

SUPPORTS
THIRD PARTY
COMMENTS (MISO)

SUPPORTS
THIRD PARTY
COMMENTS (Dean Fox)
SUPPORTS
THIRD PARTY
COMMENTS (MISO)

7

5

Electric Power Supply Association

John R Cashin

5

Entergy Services, Inc.

Tracey Stubbs

Affirmative

5

FirstEnergy Solutions

Kenneth Dresner

Negative

5

Florida Municipal Power Agency

David Schumann

Negative

5

Gainesville Regional Utilities

Karen C Alford

5

Great River Energy

Preston L Walsh

5

Imperial Irrigation District

Marcela Y Caballero

5

JEA

John J Babik

5

Kansas City Power & Light Co.

Brett Holland

5

Lakeland Electric

James M Howard

5

Lincoln Electric System

Dennis Florom

5
5

5

Los Angeles Department of Water & Power Kenneth Silver
Manitoba Hydro
S N Fernando
Massachusetts Municipal Wholesale
David Gordon
Electric Company
MEAG Power
Steven Grego

5

MidAmerican Energy Co.

Neil D Hammer

5

Muscatine Power & Water

Mike Avesing

5

Nebraska Public Power District

Don Schmit

5

New York Power Authority

Wayne Sipperly

5

NextEra Energy

Allen D Schriver

5

Northern Indiana Public Service Co.

William O. Thompson

5

Oglethorpe Power Corporation

Bernard Johnson

5

5

Oklahoma Gas and Electric Co.

Henry L Staples

5
5
5
5

Omaha Public Power District
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority

Mahmood Z. Safi
Richard K Kinas
Bonnie Marino-Blair
Roland Thiel

5

Portland General Electric Co.

Matt E. Jastram

5

PowerSouth Energy Cooperative

Tim Hattaway

Non-Binding Poll Results
Project 2010-14.1 BAL-002-2 | March 2015

Negative

SUPPORTS
THIRD PARTY
COMMENTS PJM
Comments
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (NSRF)

Affirmative

Abstain
Affirmative
Abstain
Affirmative

Negative

SUPPORTS
THIRD PARTY
COMMENTS (NSRF)

Abstain
Negative

SUPPORTS
THIRD PARTY
COMMENTS (NPCC)

Negative

SUPPORTS
THIRD PARTY
COMMENTS (SPP Group
Comments)

Abstain
Affirmative
Affirmative
Abstain
Affirmative

8

5

PPL Generation LLC

Annette M Bannon

5

Tim Kucey

5
5
5
5
5
5
5
5

PSEG Fossil LLC
Public Utility District No. 2 of Grant
County, Washington
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.

5

Southern California Edison Company

Denise Yaffe

5
5

Southern Company Generation
Tacoma Power

William D Shultz
Chris Mattson

5

Tampa Electric Co.

RJames Rocha

5
5
5
5

Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers

Scott Helyer
David Thompson
Mark Stein
Melissa Kurtz

5

U.S. Bureau of Reclamation

Martin Bauer

5

Wisconsin Electric Power Co.

Linda Horn

5
6
6
6

Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
APS

Liam Noailles
Edward P. Cox
Jennifer Richardson
Randy A. Young

6

Associated Electric Cooperative, Inc.

Brian Ackermann

6
6
6

Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding

Brenda S. Anderson
Lisa Martin
Marvin Briggs

6

Cleco Power LLC

Robert Hirchak

6

Colorado Springs Utilities

Shannon Fair

Affirmative

6

Con Edison Company of New York

David Balban

Negative

6

Duke Energy

Greg Cecil

Negative

6

Entergy Services, Inc.

Terri F Benoit

5

6

FirstEnergy Solutions

Non-Binding Poll Results
Project 2010-14.1 BAL-002-2 | March 2015

Negative

Abstain

Michiko Sell

Affirmative

Lynda Kupfer
Susan Gill-Zobitz
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Edward Magic

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain

Kevin Querry

SUPPORTS
THIRD PARTY
COMMENTS (PPL NERC
Registered
Affiliates)

Affirmative
Affirmative
Abstain
Abstain
Affirmative
Abstain

Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative

Negative

COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Duke Energy)
SUPPORTS
THIRD PARTY
COMMENTS (FE supports

9

6

Florida Municipal Power Agency

Richard L. Montgomery

6

Florida Municipal Power Pool

Thomas Washburn

6

Florida Power & Light Co.

Silvia P Mitchell

6

Great River Energy

Donna Stephenson

6

Imperial Irrigation District

Cathy Bretz

6

Kansas City Power & Light Co.

Jessica L Klinghoffer

6

Lakeland Electric

Paul Shipps

6
6
6
6

Lincoln Electric System
Eric Ruskamp
Los Angeles Department of Water & Power Brad Packer
Luminant Energy
Brenda Hampton
Manitoba Hydro
Blair Mukanik

6

Modesto Irrigation District

James McFall

6

Muscatine Power & Water

John Stolley

6

New York Power Authority

Saul Rojas

6
6
6
6

Northern Indiana Public Service Co.
Omaha Public Power District
PacifiCorp
Platte River Power Authority

Joseph O'Brien
Douglas Collins
Kelly Cumiskey
Carol Ballantine

6

Portland General Electric Co.

Ty Bettis

6

Power Generation Services, Inc.

Stephen C Knapp

6

Powerex Corp.

Daniel W. O'Hearn

Negative
Affirmative

Negative

Negative

Elizabeth Davis

Negative

6
6
6
6
6
6
6

PSEG Energy Resources & Trade LLC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1

Peter Dolan
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
Kenn Backholm

Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative

6

Southern California Edison Company

Lujuanna Medina

Southern Company Generation and
Energy Marketing
Tacoma Public Utilities

John J. Ciza

Affirmative

Michael C Hill

Affirmative

6

Tampa Electric Co.

Benjamin F Smith II

6

Tennessee Valley Authority

Marjorie S Parsons

Non-Binding Poll Results
Project 2010-14.1 BAL-002-2 | March 2015

COMMENT
RECEIVED

Abstain
Abstain
Affirmative
Abstain

PPL EnergyPlus LLC

6

SUPPORTS
THIRD PARTY
COMMENTS (FMPA)

Abstain
Affirmative
Abstain
Affirmative

6

6

PJM
comments)
COMMENT
RECEIVED

SUPPORTS
THIRD PARTY
COMMENTS (PPL NERC
Registered
Affiliates)

Abstain

10

6
6

Westar Energy
Grant L Wilkerson
Western Area Power Administration - UGP
Peter H Kinney
Marketing

7

EnerVision, Inc.

Thomas W Siegrist

7

Steel Manufacturers Association

James Brew

8

Roger C Zaklukiewicz

8

Edward C Stein

8

Negative

Robert Blohm

8

Debra R Warner

Debra R Warner

8

Energy Mark, Inc.

Howard F. Illian

8

Terry Volkmann

Affirmative

Donald Nelson

Affirmative

10
10

Volkmann Consulting, Inc.
Commonwealth of Massachusetts
Department of Public Utilities
Florida Reliability Coordinating Council
Midwest Reliability Organization

Linda D Campbell
Russel Mountjoy

Abstain
Affirmative

10

New York State Reliability Council

Alan Adamson

10

Northeast Power Coordinating Council

Guy V. Zito

10
10

ReliabilityFirst Corporation
Texas Reliability Entity, Inc.

Anthony E Jablonski
Donald G Jones

Affirmative
Affirmative

10

Western Electricity Coordinating Council

Steven L. Rueckert

Abstain

9

SUPPORTS
THIRD PARTY
COMMENTS (NPCC)

Non-Binding Poll Results
Project 2010-14.1 BAL-002-2 | March 2015

Affirmative

Negative

COMMENT
RECEIVED

11

Consideration of Comments

Project 2010-14.1 Phase 1 of Balancing Authority
Reliability-based Controls
BAL-002-2

TheProject2010Ͳ14.1standarddraftingteamthanksallcommenterswhosubmittedcommentsonthe
BALͲ002Ͳ2standard.Thestandardwaspostedfora45ͲdaypubliccommentperiodfromJanuary29,
2015throughMarch18,2015(includinga2Ͳdayextensiontoreachquorumontheballot).
Stakeholderswereaskedtoprovidefeedbackonthestandardandassociateddocumentsthrougha
specialelectroniccommentform.Therewere24responses,includingcommentsfromapproximately
116differentpeoplefromapproximately80companiesrepresenting9ofthe10IndustrySegmentsas
showninthetableonthefollowingpages.

Allcommentssubmittedmaybereviewedintheiroriginalformatonthestandard’sprojectpage.

Ifyoufeelthatyourcommenthasbeenoverlooked,pleaseletusknowimmediately.Ourgoalistogive
everycommentseriousconsiderationinthisprocess.Ifyoufeeltherehasbeenanerrororomission,
youcancontacttheDirectorofStandards,HowardGugel(viaemail,[email protected]),orat
(404)446Ͳ9693.Inaddition,thereisaNERCReliabilityStandardsAppealsProcess.1


1

TheappealsprocessisintheStandardProcessesManual:http://www.nerc.com/comm/SC/Documents/Appendix_3A_StandardsProcessesManual.pdf



Index to Questions, Comments, and Responses


1.

PleaseprovideanyissuesyouhaveonthisdraftoftheBALͲ002Ͳ2standardanda
proposedsolution.................................................................................................................10

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

2

Arizona Electric Power Cooperative

Southwest Transmission Cooperative

6. John Shaver

7. John Shaver

1. entral Electric Power Cooperative

Additional Member

PhillipHart

South Mississippi Electric Power Association SERC

5. Steve McElhaney

Group

Sunflower Electric Power Corporation

4. Ellen Watkins

2.



Southern Illinois Power Cooperative

3. Bill Hutchison

1, 3, 4, 6

1

1, 5

3, 5

1

SERC

1, 3

Additional Organization Region Segment Selection

AssociatedElectricCooperative,Inc.

WECC 1

WECC 4, 5

SPP

SERC

SPP

Golden Spread Electric Cooperative

RFC

Hoosier Energy

Region Segment Selection

ACESStandardsCollaborators

Additional Organization

JasonMarshall

Organization

2. Chip Koloini

Additional Member

Group

Commenter

1. Bob Solomon

1.

Group/Individual

TheIndustrySegmentsare:
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

X

X

1





2

X

X

3



X

4

X

X

5

X

X

6





7





8

RegisteredBallotBodySegment





9





10

ColbyBellville

Duke Energy

Duke Energy

3. Dale Goodwine

4. Greg Cecil

DukeEnergy

Jim Howard

Greg Woessner

Lynne Mila

Randy Hahn

Stan Rzad

Don Cuevas

Mark Schultz

Javier Cisneros

2.

3.

4.

5.

6.

7.

8.

9.

Region

Fort Pierce Utility Authority

City of Green Cove Springs

Beaches Energy Services

Keys Energy Services

Ocala Utility Services

City of Clewiston

Kissimmee Utility Authority

Lakeland Electric

FRCC

FRCC

FRCC

FRCC

FRCC

FRCC

FRCC

FRCC

FRCC

Segment
Selection

FloridaMunicipalPowerAgency

6

5

3

1

City of New Smyrna Beach

RFC

SERC

FRCC

RFC

4

3

1

4

3

3

3

3

4

X

X

X

X

1









2

X

X

X

X

3

X







4

X

X

X

X

5

X

X

X

X

6









7









8

RegisteredBallotBodySegment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Tim Beyrle

1.

Additional Member Additional Organization

CarolChinn

Duke Energy

2. Lee Schuster

Group

Duke Energy

1. Doug Hils

6.



Region Segment Selection

Orange and Rockland Utilities NPCC NA

Additional Organization

ConEdison,Inc.

WECC 1

WECC 1

WECC 1

Additional Member Additional Organization Region Segment Selection

Group

1. Edward Bedder

5.



Additional Member

KellyDash

Duty Scheduling

3. Fran Halpin

Group

Technical Operations

4.



Technical Operations

2. Bart McManus

Additional Member Additional Organization Region Segment Selection

1. Dave Kirsch

1, 3

1, 3

1, 3

1, 3

BonnevillePowerAdministration

SERC

6. Sho-Me Power Electric Cooperative

AndreaJessup

SERC

5. N.W. Electric Power Cooperative, Inc.

Group

SERC

4. Northeast Missouri Electric Power Cooperative

3.



SERC

3. M & A Electric Power Cooperative

1, 3

Organization

SERC

Commenter

2. KAMO Electric Cooperative

Group/Individual









9

4









10

Terry Bilke

Ali Miremadi

Ben Li

5.

6.

7.

Segment
Selection

MRO
2

2

2

2

2

2

2

3

6

3

Omaha Public Utility District

Midwest ISO Inc.

Great River Energy

Minnesota Power

Rochester Public Utilties

MidAmerican Energy Company

Wisconsin Public Service Corporation MRO

10. Mahmood Safi

11. Marie Knox

12. Mike Brytowski

13. Randi Nyholm

14. Scott Nickels

15. Terry Harbour

16. Tom Breene

3, 4, 5, 6

1, 3, 5, 6

4

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

X



1

X

X

2

X



3

X



4

X



5

X



6





7





8

RegisteredBallotBodySegment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

MRO

MRO

MRO

MRO

MRO

MRO

MRO

Alliant Energy

MRO

MRO

9. Larry Heckert

Basin Electric Power Cooperative

6. Dave Rudolph
MRO

Minnkota Power Cooperative, Inc.

5. Dan Inman

MRO

MRO

Otter Tail Power Company

4. Chuck Wicklund

MRO

MRO

Western Area Power Administration

American Transmission Company

3. Chuck Lawrence

8. Jodi Jenson

Xcel Energy

2. Amy Casucelli

MRO

Region Segment Selection

7. Kayleigh Wilkerson Lincoln Electric System

Madison Gas & Electric

MROͲNERCStandardsReviewForum

NPCC

Additional Organization

IESO

CAISO WECC

MISO

NYISO NPCC

ISO-NE NPCC

RFC

ERCOT ERCOT
PJM

FRCC

ISO/RTOCouncilStandardsReview
Committee

Beaches Energy Services

1. Joseph Depoorter

Additional Member

Greg Campoli

4.

JoeDepoorter

Kathleen Goodman

3.

Group

Mark Holman

2.

8.



Christina Bigelow

1.

FRCC

Organization

Florida Municipal Power Pool FRCC

City of Bartow

Additional Member Additional Organization Region

CharlesYeung

Steven Lancaster

12.

Group

Tom Reedy

11.

7.



Matt Culverhouse

Commenter

10.

Group/Individual





9

5





10

Greg Campoli

Sylvain Clermont

Kelly Dash

Gerry Dunbar

Kathleen Goodman

Michael Jones

Mark Kenny

Helen Lainis

Peter Yost

Alan MacNaughton

Paul Malozewski

Bruce Metruck

Ben Wu

Lee Pedowicz

Robert Pellegrini

Si Truc Phan

David Ramkalawan

Brian Robinson

Brian Shanahan

Wayne Sipperly

3.

4.

5.

6.

7.

8.

9.

10.

11.

12.

13.

14.

15.

16.

17.

18.

19.

20.

21.

22.

Brenda Truhe

'Aine Hasham-Lawence

2.

3.

Region

NPCC

NPCC

NPCC

NPCC

NPCC

NPCC

NPCC

NPCC

NPCC

NPCC

NPCC

NPCC

NPCC

NPCC

NPCC

NPCC

NPCC

NPCC

NPCC

NPCC

PPL Generation, LLC

Segment
Selection
SERC
RFC

PPL Electric Utilities Corporation RFC

LG&E and KU Energy, LLC

Region

PPLNERCRegisteredAffiliates

New York Power Authority

National Grid

Utility Services

Ontario Power Generation, Inc.

Hydro-Quebec TransEnergie

The United Illuminating Company

Northeast Power Coordinating Council

Orange and Rockland Utilities Inc.

New York Power Authority

Hydro One Networks Inc,

New Brunswick Power Corporation

Consolidated Edison Co. of New York, Inc. NPCC

Independent Electricity System Operator

Northeast Utilities

National Grid

ISO - New England

Northeast Power Coordinating Council

Consolidated Edison Co. of New York, Inc. NPCC

Hydro-Quebec TransEnergie

New York Independent System Operator

Orange and Rockland Utilities Inc.

5

1

3

Segment
Selection

X

5

1

8

5

1

1

10

1

6

1

9

3

2

1

1

2

10

1

1

2

3

10

X

1



X

2

X

X

3





4

X

X

5

X

X

6





7



X

8

RegisteredBallotBodySegment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Charlie Freibert

1.

Additional Member Additional Organization

1, 3, 5

NortheastPowerCoordinatingCouncil

MRO

Organization

New York State Reliability Council, LLC

BrentIngebrigtson

David Burke

2.

Group

Alan Adamson

1.

10.



GuyZito

Nebraska Public Power District

Commenter

Additional Member Additional Organization

Group

17. Tony Eddleman

9.



Group/Individual



X

9

6



X

10

Seattle City Light

Seattle City Light

4. Mike Haynes

5. Dennis Sismaet

Individual

Individual

Individual

Individual

Individual

15.

16.

17.

18.

19.

TerryBilke

KathleenGoodman

LeonardKula

SiTrucPHAN

ChristinaBigelow

RichardVine

2

2

MISO

ISONewEngland

IndependentElectricitySystemOperator

HydroͲQuebecTransEnergie

ERCOT

CaliforniaISO

ArizonaPublicServiceCompany

SPP

SPP

2

1, 5

6

6

6

6

6

6

5

5







X





X

X

X

1

X

X

X



X

X



X



2













X



X

3

















X

4













X

X

X

5













X



X

6



















7



















8

RegisteredBallotBodySegment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Individual

14.

KristieCocco

Southwest Power Pool

4. Carl Stelly

Individual

Southwest Power Pool

3. Jason Smith

13.



Southwest Power Pool

SPP

Western Farmers Electric Cooperative SPP

Region Segment Selection

2. Shannon Mickens

Additional Organization

SPPStandardsReviewGroup

WECC 6

WECC 5

WECC 4

WECC 3

WECC 1

1. Darryl Boggess

Additional Member

RobertRhodes

Seattle City Light

3. Hao Li

Group

Seattle City Light

2. Dana Wheelock

12.



Seattle City Light

1. Pawel Krupa

Additional Member Additional Organization Region Segment Selection

SeattleCityLight

NPCC

11.

PaulHaase

WECC

10.

Group

SPP

9.

11.



SERC

8.

MRO

WECC
RFC

PPL EnergyPlus, LLC

6.

RFC

Organization

7.

PPL Montana, LLC

5.

Elizabeth Davis

PPL Susquehanna, LLC

Commenter

4.

Group/Individual



















9

7



















10

Individual

Individual

21.

22.

RoLyndaShumpert
PamelaHunter

AnthonyJablonski

CatherineWesley

JaredShakespeare

Commenter





X

1

X
SouthCarolinaElectricandGas
X
SouthernCompany:SouthernCompany
Services,Inc.;AlabamaPowerCompany;
GeorgiaPowerCompany;GulfPower
Company;MississippiPowerCompany;
SouthernCompanyGeneration;Southern
CompanyGenerationandEnergyMarketing

ReliabilityFirst

PJMInterconnection

PeakReliability

Organization

X
X









3





X



2











4

X

X







5

X

X







6











7











8

RegisteredBallotBodySegment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Individual
24. Individual

23.

Individual

20.

Group/Individual











9

8





X





10



Agree
Agree
Agree



HydroͲQuebecTransEnergie

ISONewEngland

SouthCarolinaElectricand
Gas

ERCOT

Agree

ISO/RTOCouncilStandardsReviewCommittee

PJM

NPCCRSCandIRCSRC



ISO/RTOCouncilStandardsReviewCommittee

SupportingCommentsof“EntityName”

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Agree

CaliforniaISO

Organization



Ifyousupportthecommentssubmittedbyanotherentityandwouldliketoindicateyouagreewiththeircomments,pleaseselect
"agree"belowandentertheentity'snameinthecommentsection(pleaseprovidethenameoftheorganization,tradeassociation,
group,orcommittee,ratherthanthenameoftheindividualsubmitter).


SummaryConsideration:

9







10

(4)Weareconfusedaboutthe“oneͲminuteintervalthatdefinesaBalancingContingency
Event”languageintheContingencyEventRecoveryPerioddefinition.Wecanfindno
referenceto“oneͲminute”intheBalancingContingencyEventdefinition.Thereis,
however,suchareferenceintheReportableBalancingContingencyEvent.Furthermore,
theoneͲminuteintervalreallydoesnotdefinetheeventbutratherpreͲdisturbancelevel

(3)WecontinuetobelievethatthethresholdsdefinedintheReportableBalancing
ContingencyEventarearbitrary.Weaskthatthedraftingteamprovideatechnicalbasis
forthevaluesinsteadoftheexistingexplanationintheBackgrounddocument.Whilewe
understandthatthedraftingteamreviewedsomedata,thereareuncertaintiesregarding
howvalueswereidentifiedfromthedataandthenanothervaluewasselected.

(2)PleasestrikethelastsentenceoftheReportableBalancingContingencyEvent.Itis
administrativeinnatureandshouldbehandledthroughcompliancemonitoringprocesses.
IfNERCwantstoknowifanentityhasmodifieditsreportablethreshold,theyhavea
myriadofcompliancemonitoringprocessesandtoolstogatherthisinformation.Itdoes
notneedtobedocumentedinaglossarydefinition.Furthermore,itisnotreallya
definitionbutratheranexplanationandtherefore,doesnotbelonginthedefinition.

(1)TheMostSevereSingleContingencydefinitionandapplicabilitysection4.1.1.1should
bemodifiedtoreflectthatthestandardsimplyappliestoaBAorRSGbystriking“thatis
notparticipatingasamemberofaRSGatthetimeoftheevent”.Thislanguagemay
conflictwithexistingRSGcontracts.Furthermore,itisaregistrationissueonwhetherthe
standardappliestotheBAorRSGinthesesituations.WhentheRSGregisterswithNERC,
NERCwilltypicallyreviewthecontracttounderstandhowtheRSGisformed.Ifthe
standardshouldapplytotheBAincertainsituationsandtheRSGinothers,thisshouldbe
documentedinacoordinatedfunctionalregistration,notinastandardsdefinitionor
applicabilitysection.Whatdoesitevenmeantobein“activestatus”underapplicability
section4.1.1.1?0

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

ACESStandardsCollaborators

Question1Comment

PleaseprovideanyissuesyouhaveonthisdraftoftheBALͲ002Ͳ2standardandaproposedsolution.

Organization

1.

11

(8)Although,wedonotopposetheuseofCRForm1,Part1.1shouldbestruckasitis
administrativeinnature.AviolationofPart1.1couldneverresultinaharmtoreliability.

Wedisagreewiththestatementthatthelanguagemakesthestatementambiguous.A
BalancingAuthoritymayrequestthattheRCissueanEEA.Thelanguagewasputinthe
requirementtoclarifythattheEEAmustbeapprovedbytheReliabilityCoordinatorprior
totheentitybeingexcusedfromtherequirement.IftheEEAisnotdeclareduntilafterthe
15minutes,thentheentityisnotexcused.HowevertheSDTmodifiedthedefinitionand
removedthelanguage.

(7)Theinsertionofthe“ReliabilityCoordinatorapproved”inPart1.2createsadditional
confusionbyimplyingthatanEEAcanbeissuedwithoutRCapproval.AnEEAcannotbe
issuedwithoutRCapproval.Thus,thislanguageissuperfluous,onlyaddsambiguityand
confusiontothepartandshouldbestruck.

Thedraftingteamagreeswiththiscommentandhasmadethemodification.

(6)ReportableAreaControlErrorintheRationaleboxforR1shouldbechangedto
ReportingACEtomatchtheNERCGlossary.

ThedraftingteamdisagreeswiththisoverͲsimplificationofwhatisorcanprovide
contingencyreserve.However,theSDTmodifiedthedefinitionbasedonindustry
commentsreceived.

(5)WedisagreewiththedefinitionofContingencyReserve.Thedefinitionshouldbe
modifiedtosimplyreflectthatContingencyReserveIsunloadedonͲlinegenerationand
quickstartoffͲlinegenerationcapableofbeingdispatchedin15minutes.Thecurrent
definitionmaylimittheuseofContingencyReserveandmayomitoffͲlinequickstart
generationsinceunloadedgenerationusuallyreferstoonͲlinegenerators.

ThelanguageofaBalancingContingencyEventshouldbebroaderthanthatinthe
ReportableBalancingContingencyEvent.TheReportablegroupisasubsetoftheBCE.

beforethestartoftheevent.ThelanguageintheContingencyEventRecoveryPeriod
needstobecleaneduptoreflectthisinformation.

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Organization

12

(10)WedisagreewiththearbitraryselectionoffiveminutesinPart2.6fortheexemption
toapply.Webelievethefiveminutesisarbitraryandlanguageisambiguouswhichwill
onlyleadtoinconsistentcomplianceoutcomes.Whatwouldbeconsideredpreparations?
Sendingtechstothestations?Armingloadingsheddingschemes?Thinkingaboutit?
Thereneedsadditionalclarificationinthestandard.

TheSDThasremovedthelanguagereferencedandmodifiedtherequirementtohavea
processforContingencyReserveintheirOperatingPlan.

(9)Whileweappreciatethatthedraftingteamdidattempttodocumentotheracceptable
usesofContingencyReserveinR2thatwouldnotviolatetherequirement,we
fundamentallydisagreewiththearbitraryselectionof90minutesasalimitontheuseof
ContingencyReserve.WhyshoulduseofContingencyReservebelimitedto90minutes
foranEnergyEmergency?AnEnergyEmergencycouldlastseveralhoursandBAwouldbe
forcedtoeitherviolatetherequirementorshedloadtoavoidacompliancerequirement.
Neitherisagoodoutcome.Rather,wesuggestthe90minuteperiodshouldbedropped
inParts2.1,2.2,and2.3.WeparticularlyseethisasanissueforPart2.2.IfanRCwereto
issueanOperatingInstructiontouseContingencyReservetoresolveanEEAtoavoid
sheddingload,whyshouldthishigherlevelauthoritynotbeabletoinstructtheBAto
exceedthe90minutes?ThefactthatContingencyReservemaybeusedforlongerthan
90isevendocumentedinthesecondtolastparagraphonpage36ofthebackground
document.

TheSDTisattemptingtoprovideforconsistencyinreporting.

Ifanentityweretoreportthedatainanotherformat,reliabilitywouldnotbeharmed.If
reliabilitycannotbeharmedthenastandardshouldnotcompeltheaction(inthiscase,
specificuseofareportingform).UseofaCRForm1canandshouldbehandledthrough
NERCcompliancemonitoringprocessesasNERCandtheRegionalEntitiesdowithother
reportingformatsanddatacollectionmethods.UseofCRForm1isalreadydocumented
intheRSAWwhichshouldbesufficient.

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Organization

TheSDThasremovedthelanguagereferenced.

13

(12)InMeasure2,wesuggestaddingaclausetothefirstbulletthatContingencyReserve
mustmeetorexceedtherequiredamount“unlessoneoftheexceptionsfromR2ismet”.



354.First,theCommissiondirectstheEROtodevelopamodificationtotheReliability
Standardrequiringthatanysinglereportabledisturbancethathasarecoverytimeof
15minutesorlongerbereportedasaviolationoftheDisturbanceControlStandard.
ThisisconsistentwithourpositionintheNOPRandNERC’spositioninresponseto
theStaffPreliminaryAssessmentoftheRequirementsinBALͲ002Ͳ0,andwasnot
disputedorcommenteduponbyanyNOPRcommenters.

FromOrder693

TheSDTwillworkwithNERCtoensurethattheycontinuetogetthenecessary
informationfortheirreportsandhavethatinformationaddedtothebackground
documentpriortothenextposting.Theindividualeventreportingmovesthecompliance
processtomeetthealreadyusedenforcementprocess.ThisalsosatisfiesaFERCOrder
693directive.

(11)Wedisagreewiththemovefromquarterlyreportingtoexceptionreporting.Today,
complianceisassessedonaquarterlybasis.Thisstandardappearstorequirea
ResponsibleEntitytoissueaselfͲreportanytimeitdoesnotrecover100%froma
reportableaReportableBalancingContingencyEventwithoutanybasisidentifiedforthe
change.ThiswillservetoincreaseaResponsibleEntitiescompliancecostswithoutany
commensuratebenefittoreliability.Furthermore,itwilleliminateadatasourcethat
NERCusesforitsannualstateofreliabilityreportwhichwillbedetrimentaltothereport.

TheSDThasremovedthelanguagereferencedandmodifiedtherequirementtohavea
processforContingencyReserveintheirOperatingPlan

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Organization

14

1. PleaseprovideanyissuesyouhaveonthisdraftoftheBALͲ002Ͳ2standardanda
proposedsolution.
2. Comments:PJMappreciatesandrecognizestheworkoftheSDTasreflectedinthe
presentpostingoftheproposedBALͲ002Ͳ2.PJMstronglyurgestheSDTtoincorporate
thefollowingchanges.
3. R1Suggestedchanges:R1.TheResponsibleEntityexperiencingaReportableBalancing
ContingencyEventshall,withintheContingencyEventRecoveryPeriod,demonstrate
recoverybyreturningitsReportingACEtoatleasttherecoveryvalueof:[Violation
RiskFactor:Medium][TimeHorizon:RealͲtimeOperations]

TheSDThasmodifiedtherequirement.

(15)WeareconcernedthattherequirementformattingoftheexceptionsinPart2.1
through2.6arenotconsistentwiththeinformationalfilingNERCsubmittedtoFERC
severalyearsagoregardingtheuseofbulletsandpartsinplaceofsubͲrequirements.In
thatfiling,NERCstatedthatnumberedlistsor“Parts”wouldbeusedwhenall“Parts”
mustbemetand“bullets”wouldbeusedwhenthereareexceptions.Toqualifyforan
exception,onlyoneoftheParts2.1Ͳ2.6shouldbemetnotall.Yet,useofanumberedlist
impliesthatallexceptionsmustbemet.Theformattingneedstobemodifiedtobullets
insteadofanumberedlist.

TheSDThasmodifiedtherequirementand therefore made modified the VSL’s accordingly.

(14)TheVSLsforRequirementR2shouldbemodifiedtostatethatResponsibleEntitydid
havelessthantherequiredamountofContingencyReserve“anddidnotmeetoneofthe
exceptionsinParts2.1through2.6”.

TheSDThasremovedthelanguagereferenced.

(13)InMeasure2,weareconfusedbythelanguage“excludedbyruleinRequirement
R2”.DoesthismeanexcludedbyParts2.1through2.6?Ifso,changethelanguageto
“excludedbyParts2.1,2.2,2.3,2.4,2.5or2.6”.

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

PJMInterconnection

Organization

beginningatthetimeof,and
(ii)bythemagnitudeof,eachindividualBalancingContingencyEvent.

15

o(iii)whentheResponsibleEntityisoperatingundertheconditionsdescribedinR2,
initsentirety.

o(ii)aftermultipleBalancingContingencyEventsand/orContingencyeventsthat
arenotBalancingContingencyEventsforwhichthecombinedmagnitudeexceeds
theResponsibleEntity'sMostSevereSingleContingencyforthoseeventsthatoccur
withina105Ͳminuteperiod,or

o(i)whentheResponsibleEntityexperiencesaBalancingContingencyEventthat
exceedsitsMostSevereSingleContingency,or

1.3.RequirementR1(initsentirety)doesnotapply:

1.2.AResponsibleEntityisnotsubjecttocompliancewithRequirementR1whenitis
experiencingaReliabilityCoordinatorapproveddeclaredEnergyEmergencyAlertLevel
underwhichContingencyReserveshavebeenactivatedordepletedbelowreserve
requirements.

(i)
(ii)

oItsPreͲReportingContingencyEventACEValue,(ifitsPreͲReportingContingency
EventACEValuewasnegative);however,duringtheContingencyEventRecovery
Period,anyBalancingContingencyEventeventthatoccursshallreducetherequired
recovery:

oZero,(ifitsPreͲReportingContingencyEventACEValuewaspositiveorequalto
zero);however,duringtheContingencyEventRecoveryPeriod,anyBalancing
ContingencyEventeventthatoccursshallreducetherequiredrecovery:
(i)
beginningatthetimeof,and
(ii)
(ii)bythemagnitudeof,eachindividualBalancingContingency
Eevent,or,

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Organization

16

R2.6.inanEnergyEmergencyAlertLevelunderwhichtheResponsibleEntitynolonger
hasrequiredContingencyReserve.availableprovidedthattheResponsibleEntityhas
madepreparationsforinterruptionofFirmLoadtoreplacetheshortfallofContingency
Reservetoavoidtheuncontrolledfailureofcomponentsorcascadingoutagesofthe
Interconnection.Forthisexemptiontoapply,thepreparationsmustbeinitiatedwithin
5minutesfromthetimethattheEnergyEmergencyAlertLevelisdeclared.


R2.6SuggestedChanges:ShouldthepresentlydraftedR2andassociatedsubͲ
requirementsremaininthestandard,PJMbelievesR2.6isnotacceptableinitspresent
language.Anecessaryrevisionwouldbeasfollows:

TheSDThasremovedthelanguagereferencedandmodifiedtherequirementtohavea
processforContingencyReserveintheirOperatingPlan

R2Discussion:PJMurgesincorporationofoursuggestedrevisiontoR2.PJMwouldbe
supportiveofastandardthatincorporatedourproposedrevision.Thisrevision
recognizesthattheprocurementofContingencyReservesisaccomplishedinthe
OperationPlanningtimehorizonandthatR2aspresentlydraftedisoverlyprescriptive.

R2Suggestedchanges:R2.TheResponsibleEntityshalldevelopandmaintainan
OperatingPlantoprocureContingencyReservecapacityforeachhourgreaterthanor
equaltoitsMostSevereSingleContingencyforthathour.

IfyoulookatthedefinitionofReportableBalancingContingencyEvent,youwillsee
thattheyarelimitedtoeventsthatoccurwithinaoneͲminutetimeperiod.Inyour
example,eithertheeventwouldnotbereportableiftherunbackgoesformorethan
oneminute,ortherunbackMWswouldbeusedtoadjusttheACErecoveryforthe
Reportableevent.DoesCRForm1allowforlossofunloadedcapacity?

TheSDThasmodifiedRequirementR1.

R1Discussion:PJMviewsitasnecessarytoincludetheMWlossesassociatedwithunits
thatmayrampdownorbederatedwhichalsoresultinalossofoutputorcapacity.CR
Form1needstobemodifiedtoaccountforthesuggestedchangesinR1.

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Organization

17

1. TheSRCgenerallysupportsR1.Forclarity,andtoaddressaconcernthateventsthat
donotsuddenasdefinedintheterm“BalancingContingencyEvent”(suchasramping,
derating,etc.)areexcludedfromtherecoveryconsideration,theSRCsuggeststhe
followingminorclarificationtoR1forconsideration:
R1.TheResponsibleEntityexperiencingaReportableBalancingContingencyEvent
shall,withintheContingencyEventRecoveryPeriod,demonstraterecoveryby
returningitsReportingACEtoatleasttherecoveryvalueof:
oZero,(ifitsPreͲReportingContingencyEventACEValuewaspositiveorequalto
zero);however,duringtheContingencyEventRecoveryPeriod,anyContingency
eventthatoccursshallreducetherequiredrecovery:beginningatthetimeof,and
bythemagnitudeof,eachindividualContingencyevent,or,
oIt'sPreͲReportingContingencyEventACEValue,(ifitsPreͲReportingContingency
EventACEValuewasnegative);however,duringtheContingencyEventRecovery
Period,anyContingencyeventthatoccursshallreducetherequiredrecovery:
beginningatthetimeof,andbythemagnitudeof,eachindividualContingency
event.(i.e.,strikeout(i)and(ii))
WefurthersuggestPart1.2berevisedtoread:
1.2. AResponsibleEntityisnotsubjecttocompliancewithRequirementR1when:

TheSDThasremovedthelanguagereferencedandmodifiedtherequirementtohaveaprocess
forContingencyReserveintheirOperatingPlan

R2.6Discussion:LoadsheddingplansareadequatelyaddressedintheEOPstandards.
RequirementR2.6asproposedisadistractionfortheSystemOperatorthathasno
positiveimpactonreliability.TherequirementaswrittenrequiresthatFirmLoadbe
shedtoreplaceashortfallofContingencyreserves.Whywouldanentityshedloadto
maintainreserveswhensheddingloadviaSCADAcanbeaccomplishedquickerthan
loadingContingencyReserves?


TheSDThasremovedthelanguagereferencedandmodifiedtherequirementtohavea
processforContingencyReserveintheirOperatingPlan

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

ISO/RTOCouncilStandardsReview
Committee

Organization

3.Inaddition,theproposedR2hasthefollowingpotentialadverseconsequences:

18

TheSDThasmodifiedtherequirementtohaveaprocessforContingencyReserveintheir
OperatingPlan

oIthasexperiencedmultipleBalancingContingencyEventsand/orContingency
eventsthatarenotBalancingContingencyEventsforwhichthecombinedMW
lossexceedstheResponsibleEntity'sMostSevereSingleContingencyforthose
eventsthatoccurwithina105Ͳminuteperiod.

Wedisagreewiththiswording.EventsgreaterthanMSSCareexcludedfromR1by
definitionofReportableBalancingContingencyEvent.

2. Inourpreviouscomments,theSRCstatedthatitfoundRequirementR2confusingand
thattherequirementitselfwasunnecessaryforsolongastheBAmettherequirement
inR1.HavingR1thatrequiresaBAtomeettheACErecoveryrequirementfollowingan
MSSCeventwouldsufficetodrivetheproperbehaviorofsecuringadequatereserve
aroundtheclock(exceptthoseconditionslistedinR1).Ifandwhenacontingency
occursandtheaffectedBAdoesnothavesufficientreservetorecoverACE,thenitwill
failR1whereasifR2aspresentedisretained,thenaBAcouldfailbothrequirements.
ThereisnoneedforhavingR2tosupportR1,whichcanresultindoublejeopardy.
Note:ERCOTdoesnotsupportthiscomment.

oItexperiencesaBalancingContingencyEventthatexceedsitsMostSevereSingle
Contingency.

TheSDThasremovedthelanguagereferencedandmodifiedtherequirementto
haveaprocessforContingencyReserveintheirOperatingPlan

oItisexperiencingaReliabilityCoordinatorissuedEnergyEmergencyAlertLevel
underwhichContingencyReserveshavebeenactivatedordeleted.

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Organization

19

4. WeunderstandthattheintentoftheproposedR2istorequireaBAtodemonstrate
thatitmaintainsContingencyReserve,averagedovereachClockHour,greaterthanor
equaltoitsaverageClockHourMostSevereSingleContingency,exceptundercertain
circumstances.IftheSDT’sintentistoensurethataBAconsidereventsotherthan
MSSCthatcouldreducetheamountofreserve,thentomeetthisintentwesuggest
replacingR2withthefollowing:
R2.TheResponsibleEntityshalldevelopoperationalplansthatprovidesufficient
ContingencyReserveconsideringothereventsthatmayreducethisamount.
WebelievethistogetherwiththerecoveryprovisioninR1andtheprovisionin
RequirementR6andAttachment1ofEOPͲ011Ͳ1wouldcollectivelytakecareofmany
oftheconditionslistedintheproposedRequirementR2includingactivemonitoringof
theamountofreservetomeettheContingencyReserverequirement.Toincludethe
remainingconditionsthatarenotalreadyaccountedforunderwhichaBAmaynotbe
abletomaintaintherequiredamountANDduringwhichanMSSCeventoccurs

oEntitiessheddingfirmcustomerloadtomaintainreservestomeetcompliancewiththis
requirement,which,again,isnottherightactiontotakeforreliability.

TheSDThasmodifiedtherequirementtohaveaprocessforContingencyReserveintheir
OperatingPlan

TheSDTdoesnotseeanydifferencethanwhatiscurrentlyrequired.

oOperatorsnotdeployingreserveswhenneededforreliabilityinordertomeet
compliancewiththisrequirement,whichcouldbedetrimentaltoreliability;and/or

oAnincreaseinreservesinordertomaintainanamountoverͲandͲabovethatrequired
bythestandardtomeetnonͲDCSoperationalevents,therefore,costingtheratepayers
additionalmoniesfornoincreaseinreliability(Note:IESOdoesnotsupportthis
comment);

TheSDThasmodifiedtherequirementtohaveaprocessforContingencyReserveintheir
OperatingPlan

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Organization

Whiletheexampleyouprovideworksverywellforthesingleentitythatitcovers,this
typeofstructureisnotlikelytoworkforanationͲwidestandard.Thestandardcovers
20

Theterm“sudden”isusedinthedefinitionofawidecategory.Thiscategorymaybeused
torefinetheneededrecoveryforaReportableBalancingContingencyEventunderR1in
theproposedstandard.Thedraftingteambelievesthatasstructured,theterm“sudden”
doesnotneedfurtherdefinitionasanydefinitivedefinitionwouldbesomewhatarbitrary
andpossiblyillͲfittingforonesizeentitywhileperfectlyreasonableforanother.

1.Inthelastposting,weexpressedaconcernwiththeterm“suddenloss”(seebelow).We
areunabletofindanyresponseintheSummaryConsiderationreportthataddressesthis
comment.Pleaseconsiderthesecommentsandprovidearesponse.ABalancing
ContingencyEventisvaguelydefinedasa“Suddenlossofgeneration...”or“sudden
declineinACE...”.Thewordsuddenisimprecise,andshouldbeclarified.Wesuggestthat
thestandardbecleareraboutdefiningthestarttimeforaReportableBCE.Wesupport
definitionslikethatusedinNPCCDirectory5section5.17whereitsaysthatthestartofan
eventhasoccurredwhenaspecificXamountofMWsarelostinaspecificYamountof
time.Therefore,wesuggestthatthedraftingteamaddprecisionindeterminingminute
T+0foraneventbyaddingthefollowingsentence(orsomethinglikeit)totheReportable
BCEdefinition:“Followingtheresourcefailure,theReportableBCEstartingtimeisdefined
asthefirstchronologicalrollingoneminuteintervalthatmeetsthereductioninresource
output(s)criteriastatedherein.”TheSDT’sresponsetocommentdoesnotappearto
addressthisparticularcomment.WeasktheSDTtopleaseprovidetherationaleastowhy
thissuggestionwasnotadopted.

TheSDThasremovedthelanguagereferencedandmodifiedtherequirementtohavea
processforContingencyReserveintheirOperatingPlan.

therebyrenderingaBAunabletomeetrequirementR1,thenthefollowingbulleted
itemsmaybeaddedunderPart1.3inR1:oWhentheResponsibleEntityisusingits
ContingencyReserveforaperiodnottoexceed90minutes,toresolvetheexceedance
ofaSystemOperatingLimit(SOL)orInterconnectionReliabilityOperationLimit(IROL)
Note:ERCOTdoesnotsupportthiscomment.

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

IndependentElectricitySystem
Operator

Organization

21

R2.TheResponsibleEntityshalldevelopoperationalplansthatprovidesufficient
ContingencyReserveconsideringallothereventsthatmayreducethisamount.We
believethistogetherwiththerecoveryprovisioninR1wouldtakecareofmanyofthe
conditionslistedintheproposedRequirementR2.Toincludetheremainingconditions
thatarenotalreadyaccountedforunderwhichaBAmaynotbeabletomaintainthe
requiredamountANDduringwhichanMSSCeventoccurstherebyrenderingaBAunable
tomeetrequirementR1,thenthefollowingbulleteditemsmaybeaddedunderPart1.3in
R1:oWhentheResponsibleEntityisusingitsContingencyReserveforaperiodnotto

2.Inourpreviouscomments,wefoundRequirementR2confusingandthatthe
requirementitselfwasunnecessaryforsolongastheBAmettherequirementinR1.
HavingR1thatrequiresaBAtomeettheACErecoveryrequirementfollowinganMSSC
eventwouldsufficetodrivetheproperbehaviorofsecuringadequatereservearoundthe
clock(exceptthoseconditionslistedinR1).Ifandwhenacontingencyoccursandthe
affectedBAdoesnothavesufficientreservetorecoverACE,thenitwillfailR1whereasif
R2aspresentedisretained,thenaBAcouldfailbothrequirements.Thereisnoneedfor
havingR2tosupportR1,whichcanresultindoublejeopardy.R2aspresentedinthisdraft
requiresaBAtodemonstratethatitmaintainsContingencyReserve,averagedovereach
ClockHour,greaterthanorequaltoitsaverageClockHourMostSevereSingle
Contingency,exceptundercertaincircumstances.IftheSDT’sintentistoensurethataBA
considereventsotherthanMSSCthatcouldreducetheamountofreserve,thentomeet
thisintentwesuggestreplacingR2withthefollowing:

Thedraftingteamdisagreeswiththeneedtoaddasentencetothedefinitionof
ReportableBCE.ThestartingtimeofaneventisdeterminedbythedefinitionofPreͲ
ReportingContingencyEventACEValue.

entitiessuchasrelativelysmallBalancingAuthoritieslikeLADWPtoverylargeentities
suchasPJM.ThereforeastatedMWamount,orevenastatedpercentagewouldnottreat
allentitiesevenlyorfairly.Thedraftingteamsupportstheconceptthateachentitycould
providefurtherdefinitionthroughwrittenprocedurestoclarifyhowthatentity
implementstheirprogram.

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Organization

22

Thissectionmayormaynotbeusedinthestandard.TheSDTdevelopedanOperating
ReserveGuidelinewhichcouldhavebeenincludedinthissection.However,theSDT
decidedtodeveloptheguidelinethroughtheNERCOperatingCommittee.Thisallowsfor
theguidelinetobeusedforotherstandardsandnotjustBALͲ002.

ApplicationGuidelines,GuidelinesandTechnicalBasis,TrainingMaterial,Reference
Materialand/orotherSupplementalMaterialsection:thereisnosubstantialinformation
containedinthissectionofthedocument.IsittheintentofthedraftingteamtofillͲin
thesesectionsatalaterdate?Ifso,whenwoulditbecompleted?Ifnot,whynot?

Theexistingstandardrequires15minuterecoveryfortheseevents.Thedraftingteamhas
notproposedtochangethecurrentrecoveryperiod.Iftheindustrydesirestochangethe
recoveryperiodto30minutes,studieswouldneedtobemadetodeterminethepotential
impacttoreliability.Thedraftingteamdoesnotbelievethatastudycanshowlessriskto
theBESbyextendingtherecoveryperiod.Itisunclearwhatcouldbeshowntoensurethat
alongerrecoveryperiodwouldprovideanAdequateLevelofReliability.

AECIrespectfullyrequeststhattheSDTfurtherconsidermodifyingtheContingencyEvent
RecoveryPeriodto30minutes,orprovideempiricalevidencethatdemonstratesariskto
reliabilityexistswhenaResponsibleEntityexceeds15minutesbeforerecoveringtheirACE
tothepreͲdisturbancelevel.Absentarisktoreliabilitywhenexceeding15minutes,the
useof30minutesfortheContingencyEventRecoveryPeriodwouldmorecloselyalign
withotherreliabilitystandardsrequirementsthatrelatetooperationoftheBESduring
events,specificallytheamountoftimeallowedforanentitytoexceedanIROL.

TheSDThasremovedthelanguagereferencedandmodifiedtherequirementtohaveaprocessfor
ContingencyReserveintheirOperatingPlan.

exceed90minutes,toresolvetheexceedanceofaSystemOperatingLimit(SOL)or
InterconnectionReliabilityOperationLimit(IROL)

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

ConEdison,Inc.

AssociatedElectricCooperative,Inc.

Organization

TheSDThasmodifiedtherequirementandthereforemodifiedtherationale.

23

ContingencyReserveshouldprobablybecapitalizedinthe1st,2ndand4thparagraphsof
theRationaleBoxforRequirementR2.

Uselowercase‘requirement’inthe3rdlineoftheBackgroundmaterial.(Didnotlookat
this.)

TheSDTagreesandhasmadethenecessarychanges.

SeveralstandardsrecentlyhaveforegonetheEffectiveDatesectioninthestandardand
insteadrefertotheImplementationPlanforthespecificimplementationdates.Should
thatbeconsideredhere?

Basedonthedraftingteam’sreviewofthedefinedterm,webelievethatthecurrentterm
ismoreappropriate.

Shouldn’t‘transmission’asusedinthedefinitionofBalancingContingencyEventinA.a.iii.
andB.becapitalized?

BALͲ002Ͳ2

IfaBalancingAuthorityisexperiencinganEEAeventunderwhichitscontingencyreserves
havebeenactivated,theRSGinwhichitresideswouldalsobeconsideredtobeexempt
fromR1compliance.TheRCshouldhavegonethroughallstepspriortoanEEA.

APSwouldliketheDraftingTeamtoclarifythefollowingquestionaboutthedraft
language.R1.2states“AResponsibleEntityisnotsubjecttocompliancewith
RequirementR1whenitisexperiencingaReliabilityCoordinatorapprovedEnergy
EmergencyAlertLevelunderwhichContingencyReserveshavebeenactivated.”Since
onlyaBalancingAuthoritycanbedeclaredtobeinanRCͲapprovedEEA,howwouldthat
impacttheRSGthattheBalancingAuthorityisamemberofsincethatwouldbehowthey
wouldbereportingtheircompliancewithR1?Differentlystated,doestheRSGthattheBA
isamemberofreceiveawaiverfromR1ifthememberBAisinanRCͲapprovedEEA?

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

SPPStandardsReviewGroup

ArizonaPublicServiceCompany

Organization

24

Replace‘requirement’with‘directive’inthelastlineofthe2ndparagraphunderBalancing
ContingencyEventonPage5.

Replace‘therealͲtimeoperations’with‘RealͲtimeoperations’inthe1stlineofthe1st
paragraphunderBalancingContingencyEventonPage5.

Replace‘Standard’inthe6thlineofthesameparagraphwith‘standards’.

Insert‘(MSSC)’immediatelyfollowing‘MostSevereSingleContingency’inthe2ndlineof
the2ndparagraphonPage4.

Replace‘BalancingAuthorityorReserveSharingGroup’with‘BalancingAuthority(BA)or
ReserveSharingGroup(RSG)’inthe9thlineofthe3rdparagraphonPage3.Subsequent
usesofthesetermsshouldthenbeBAorRSG,respectively.

Consistencyisneededthroughoutthedocumentinthecapitalizationoftermssuchas
‘Transmission’,‘ContingencyReserve’,‘requirements’,‘TransmissionLine’,‘Responsible
Entity’,‘Load’,‘RealͲtime’,‘energydeficiententities’,‘event’,‘fieldtrials’and‘firmload’.
Insomesituations,theSDTuses‘SDT’andinothersitsimplyuses‘draftingteam’.Be
consistentthroughout.

BackgroundDocument

Deletethe‘s’on‘suites’inthe11thlineofthe2ndparagraphoftheRationaleBoxfor
RequirementR2.

TheSDThasmodifiedtherequirementand therefore modified the rationale.

Shouldn’t‘load’becapitalizedinthe4thparagraphoftheRationaleBoxforRequirement
R2?

TheSDThasmodifiedtherequirementand therefore modified the rationale.

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Organization

25

BPAisinagreementwiththeproposedstandard,however,believesthereshouldbea
clarifyingcommentinrequirementR1.InR1,followingbothsubͲbulletsofR1,BPAwould
liketostate:

IncellA4oftheCalculatortab,insert‘the’between‘Enter’and‘name’.

IncellA11oftheEntryInstructionstab,insert‘with’between‘associated’and
‘subsequent’.

IncellA1oftheExemptiontab,replace‘Exemp’with‘Exempt’.IncellsA10andA16ofthe
Descriptiontab,©appearsinsteadoftheintended(c).ThanksMicrosoft.

IncellA15oftheReadMetab,uselowercase‘it’.

CRForm1

TheSDThasreviewedtheBackgroundDocumentandbelievesthatithasmadeall
necessarycorrections.

ThereisnoFootnote3asreferencedinthe3rdlineoftheparagraphunderControl
PerformanceStandards(CPS1)onPage34.

Thereferencesitedinthelastlineofthe2ndparagraphonPage34(Footnote5)isnot
attached.It’sreferencedinFootnote5.

TheSDTistobecommendedfortheimprovedclarityintheexamplesinAttachment2.

Replace‘suites’with‘suite’inthe1stlineinthe1stparagraphatthetopofPage10.

Replace‘requirements’with‘directives’inthe4thlineofthe4thparagraphonPage9.

Replacethe3rdbulletatthetopofPage7withthefollowing:‘resolvingtheexceedanceof
aSystemOperatingLimit(SOL)orInterconnectionReliabilityOperatingLimit(IROL)that
requirestheuseofContingencyReserves;and’.

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

BonnevillePowerAdministration

Organization

ERCOT

26

1. DefinitionsͲERCOTreiteratesitspreviouscommentsregardingtheReportable
BalancingContingencyEventthresholdscontainedwithinthedefinitionofa
ReportableBalancingContingencyEvent.ERCOTbelievesthattheintroductionof
various,differingthresholdscreatesunnecessarycomplexityandwouldproposea
1000MWthresholdforitsinterconnectionassuchthresholdalignswiththecurrent
practice.Further,ERCOTreportsother,smallereventstoNERCanditsRegionalEntity
throughdifferentmechanismsand,therefore,withdifferingreportingthresholds,the
sameeventcanbereportedtoNERCmultipletimesunderdifferentrequirements.
Accordingly,sincethethresholdlimitsrelateonlytoreportingandassociated

ERCOTcommendsthedraftingteamontheireffortstoimproveBALͲ002Ͳ2.However,it
hasconcernsandrecommendationsregardingtheproposedmodifications.These
concernsandrecommendationsaredescribedbelowbyRequirement.Proposedrevisions
areitalicized.

TheSDThasmodifiedtherequirementtohaveaprocessforContingencyReserveintheir
OperatingPlan.

Finally,BPAproposesthatR22.6spellsoutthatitonlypertainstoanEEA3.Thereasonfor
thisisthatexemptiononlyappliestoEEAlevel3inEOPͲ011Ͳ1EmergencyOperations.In
thatnewstandard,EEA3isdefined,inpart,asasituationwhere“Theenergydeficient
BalancingAuthorityisunabletomeetminimumContingencyReserverequirements.”EEA
2languageclearlystatesthatwhileaBAcannolongermeetallofitsexpectedenergy
requirements:“AnenergydeficientBalancingAuthorityisstillabletomaintainminimum
ContingencyReserverequirements.”

TheSDTreviewedtherequirementanddeterminedthatthepresentlanguagesufficiently
coveredallsituations.

”ForallsubsequenteventsthatoccurduringtheinitialContingencyEventRecovery
Period,thePreͲReportingContingencyEventACEValueforthatinitialeventmustbeused
forthesubsequentevent(s).”

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Organization

27

ERCOTrecommendsmodificationstosubpart1regardingthedepletionofcontingency
reservesbecausecontingenciesthatdepletereservescanoccurwithoutformal
“activation”ofreservesandwithouta“sudden”ortriggeringevent.Thus,itrespectfully
suggeststhattherequirementshouldbemodifiedtoensurethatacknowledgmentofsuch
reservedepletion.

oIthasexperiencedmultipleBalancingContingencyEventsforwhichthe
combinedMWlossexceedstheResponsibleEntity'sMostSevereSingle
Contingencyforthoseeventsthatoccurwithina105Ͳminuteperiod.

oItexperiencesaBalancingContingencyEventthatexceedsitsMostSevere
SingleContingency

oItisexperiencingaReliabilityCoordinatorissuedEnergyEmergencyAlert
LevelunderwhichContingencyReserveshavebeenactivatedordepleted.

1.2.AResponsibleEntityisnotsubjecttocompliancewithRequirementR1when:

3.RequirementR1.2andRequirementR1.3ͲERCOTrecommendstheconsolidationof
R1.2andR1.3andadditionalrevisionsasfollows:


TheSDThasremovedthelanguagereferencedandmodifiedtherequirementtohaveaprocess
forContingencyReserveintheirOperatingPlan

documentation,ERCOTrespectfullysubmitsthatloweringthereportableevent
thresholdsdoesnotprovideanybenefittoreliability.

FERCOrder693statesthatthestandardshouldaddresseventsthatimpactfrequency
intheinterconnection.Basedonreviewofeventsoverthelast5years,thelevelsin
thedefinitionaddressthisevent.

2. RequirementR1ͲRecommendmodifyingtheaddition(ReliabilityCoordinator
Approved)toReliabilityCoordinatorIssued.

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Organization

2.2usingitsContingencyReserve,foraperiodnottoexceed90minutes,to
respondtoanOperatingInstructionrequiringtheuseofContingency
Reserve;and/or

2.1usingitsContingencyReserve,foraperiodnottoexceed90minutes,to
mitigatethereliabilityconcernsassociatedwithContingenciesthatarenot
BalancingContingencyEvents;and/or

28

R2.TheResponsibleEntityshallplantoprocureContingencyReservegreaterthanor
equaltoitsMostSevereSingleContingency,exceptduringoneormoreofthe
followingperiodswhentheResponsibleEntityis:[ViolationRiskFactor:Medium]
[TimeHorizon:RealͲtimeOperations]

4.RequirementR2ͲERCOTrespectfullysubmitsthat,asproposed,RequirementR2would
resultintheunnecessarydiversionofattentionandresourcesduringrealͲtimeoperations
toensuringthatdatarecordationanddocumentationoccurredͲratherthanthe
performanceofactivitiesthataremoredirectlyassociatedwithsustainingthereliabilityof
theBulkElectricSystem,e.g.,contingencyreservemix,monitoring,deployments,etc.
Accordingly,ERCOTrespectfullysuggeststhefollowingalternativerevisions,whichit
believesmorecloselyalignswiththeCommission’sdirectives:

Accordingly,ERCOTrecommendsthatsubpart3beclarifiedtoensurethatthelossto
whichthesubpartwouldbeapplicableisclearandunambiguous.Byaccountingfor
overallMWofloss,notthemagnitudeofcapacityloss,theapplicabilityofSubpart3
wouldbeobjectiveandeasilydiscerned.

ERCOTfurtherrecommendsrevisiontosubpart1becausepartiallyloadedgeneratorsmay
experiencecontingenciesthatremoveMWfromtheBA,whichmayreducetheavailability
ofreservesmaintainedbysuchresourcesasheadroom.Insuchacircumstance,itis
possibletohavemultiplecontingencieswheretheMWlossislessthantheMSSC,butthat
resultinsignificantorcompletereservedepletionfortheBA.

TheSDThasmodifiedRequirementR1andRequirementR2.

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Organization

othesumoftheContingencyReserveandFirmLoadavailableasasubstitutefor
unavailableContingencyReservereachestherequiredContingencyReservelevel
withinthespecifiedperiod;FailureoftheBalancingAuthoritytoprocureadequate
ContingencyReservetorespondtoitsMSSCand/orrecovertherequired
ContingencyReservelevelwithinthetimeperiodsprescribedwouldbeconsidered
anexceptionandshouldbereportedquarterly.

29

oContingencyReservehasbeenrestoredtotherequiredContingencyReservelevels
withinthespecifiedperiod;or,

oTheBalancingAuthority’sOperatingProceduresrequireprocurementof
ContingencyReserveamountsthatmeetorexceedtheContingencyReserve
requiredtorespondtoitsMostSevereSingleContingency;or,

Compliancemaybeachievedbydemonstratingthat:

Measure2couldthenbemodifiedasfollows:

2.6inanEnergyEmergencyAlertLevelunderwhichtheResponsibleEntity
nolongerhasrequiredContingencyReserveavailableprovidedthatthe
ResponsibleEntityhasmadepreparationsforinterruptionofFirmLoadto
replacetheshortfallofContingencyReservetoavoidtheuncontrolledfailure
ofcomponentsorcascadingoutagesoftheInterconnection.Forthis
exemptiontoapply,thepreparationsmustbeinitiatedwithin5minutes
fromthetimethattheEnergyEmergencyAlertLevelisdeclared.

2.5inaContingencyEventRecoveryPeriod;and/or

2.4inaContingencyReserveRestorationPeriod;and/or

2.3usingitsContingencyReserveforaperiodnottoexceed90minutes,to
resolvetheexceedanceofaSystemOperatingLimit(SOL)orInterconnection
ReliabilityOperationLimit(IROL)thatrequirestheuseofContingency
Reserve;and/or

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Organization

30

1. Theminimumrequirementforcomplianceis100percentsoanyfailuretorespond
causesanonͲcompliance.Thequestionthenishowisafinedetermined?Shoulditbe

ThedraftingteamisawareofonlyoneRSGthatcurrentlyusesareducedminimum
reportingthresholdfortheirDCScomplianceprocess.Theothersideofthedebateon
individualeventreportingversusquarterlyreportingincludesthefollowingpoints:

TheSDThasremovedthelanguagereferencedandmodifiedtherequirementtohavea
processforContingencyReserveintheirOperatingPlan.

ERCOTsuggeststhisalternativebecausethedirectivebeingaddressedrequired
developmentofacontinentwidecontingencyreservepolicy,butdidnotrequireor
prescribetrackingorreportingobligations.Theproposedmodificationsappeartonotonly
addressaproposedreservepolicy,butappeartoalsoberevisingthecurrentquarterly
reportingandprescribinganhourlytrackingandrecordation,actionsandobligationsfor
whichERCOThasbeenunabletoidentifyanassociateddirective.Suchadditionswilllikely
haveunintendedconsequencesinhowReserveSharingGroups(RSG)willoperate.In
particular,thefailureordelayofacontingencyresourcestartcanresultinrecovery
performancethatisassignedaverylowscoreforthatsingleevent,evenwhererecoveryis
onlyaminuteortwolate.Suchoutcomewouldbeaninaccurateindicatoroftheoverall
successoftherecovery,theoverallrecoveryperformance,andtheResponsibleEntity’s
effortstorecover.Further,thereareRSGswhosepurposeistomitigatesuchriskby
deployingreservesformuchsmallerevents,helpingreliabilitythroughquickrecovery
fromsmallerevents,fasterreplenishmentofreserves,andopportunityforoperatorsto
gainnecessaryexperienceregardingreservedeployment.Shouldeachrecoveryevent
becomeindividuallysanctionable,RSGswilllikelymodifytheirrulestoincreasetheir
reportablethresholdtotheinterconnectionminimum,whichwouldreducethenet
benefitstogridreliabilitydiscussedabove.Additionally,thecurrentquarterlyreporting
hasprovidedanimportantdatasourcethatisusedforNERC’sRAPAgroupandtheState
ofReliabilityReport:http://www.nerc.com/pa/RAPA/ri/Pages/DCSEvents.aspx.The
transitionawayfromquarterlyreportingtoonlyexceptionreportingwilleliminatethat
datasourceandreduceoverallvisibility.

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Organization

31

Tofacilitatetheidentificationofexceptionswhilemaintainingthevalueandbenefits
associatedwithquarterlyreporting,ERCOTrecommendsthattherebeasinglequarterly
reportforalldatacollected.Insuchareport,theRequirementR1portionwouldbevery
similartothecurrentreportingformwithanadditionalportionwhereinstancesofreserve
amountsthatwerelessthantheMSSCduringthequartercouldbereported.Such
coordinatedreportingwouldallowboththeEROandtheindustrytoevaluatereserveand
contingencydataconcurrently,providingtheopportunitytoidentifyanytrendsand/or
dependencies.

ThedraftingteamisworkingwithNERCstafftodevelopaprocessbywhichthequarterly
informationwouldstillbeavailableforthereportscited.However,thedraftingteam
recommendsthatthisdatacollectioneffortbeoutsideofandseparatefromthe
complianceprocess.

Inthediscussionofaslowerthananticipatedstartofaunit,thereisnoclearreasoningfor
howadeterminationofviolationonefailureinthequarterisadequatelyrepresented.If
weassumethatthetotalresponseprovidedinthequarterdividedbythetotalresponse
requiredinthequarter,onlytheMWsfailedtobedeliveredmatters,nottheamountof
timeafterwards.Therefore,anindividualeventevaluationprovidesforamuchbetter
meanstodeterminetheimpacttoreliabilityfromasinglefailureasopposedtoaquarterly
mishmashofallevents.Thedraftingteambelievesthatwhileaquarterlyreportmay
providegooddatafortrendanalysis,itisapoormeanstodeterminecompliance.

basedonthepercentageofeventsforwhichcompliancewas/wasnotobtained,the
percentageoffailedresponse(i.e.totalresponseneededforalleventswas1,000,
responsereceivedwas950)
2. Quarterlyreportingaveragescanmovebasedonthenumberofreportableeventsina
quarter,thesizeofreportableeventsorothervariablethatarguablehavenobearing
ontheimpacttotheBESofanentity’sfailuretomeettheresponserequirement.
Dependingontheanswertothefirstissue,thismayormaynotbeareasonable
metric.Justbecauseithasbeenusedforcompliancepurposes,thatdoesnotmeanit
isareasonablemeasureofreliabilityorimpacttoreliability.

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Organization

QuarterlyreportingofReportableBalancingContingencyEventsalongwiththereporting
ofreserveamountslessthanaBA’sMSSCaremorethansufficientforboththeEROand
responsibleBAstoidentifyandaddresscontingencyreserveissuesthatwouldthreaten
reliability.Hence,requiringBAstoprovidedocumentationofcontingencyreserves

TheSDThasremovedthelanguagereferencedandmodifiedtherequirementtohavea
processforContingencyReserveintheirOperatingPlan.

(3)athreattoreliabilityduetothediversionofresourcesthatwouldbenecessaryto
sustaincompliance.

(2)undulyburdensome,and

(1)notnecessarywhenreserverequirementsareconsideredinparimateriawithother
reliabilitystandardsobligationsofBAsasdescribedabove,

Further,ERCOTwouldsuggestthathourlycalculationand/ordemonstrationofreserve
amountsis:

TheSDThasremovedthelanguagereferencedandmodifiedtherequirementtohavea
processforContingencyReserveintheirOperatingPlan

32

ERCOTrespectfullysubmitsthattherequirementtoplanforandprocurereservesgreater
thanorequaltoaBA’sMSSCisanappropriatecontinentͲwidecontingencyreservepolicy
andthatsuchpolicy,whenconsideredincoordinationwithobligationssetforthwithin
otherapprovedreliabilitystandardssuchasEOPͲ011Ͳ1(RequirementR6)(EEA),IROͲ005Ͳ
3.1(RequirementR2)(RCmustmonitorCon.Res.,duetoberetiredwhennewIRO
standardsareapproved),andTOPͲ002Ͳ2.1b(RequirementsR5ͲR8)(alsoduetoberetired
withnewTOPstandards,didnotlookforrequirementmapping)aremorethanadequate
toensurereliability.

ThedraftingteamisworkingwithNERCstafftodevelopaprocessbywhichthequarterly
informationwouldstillbeavailableforthereportscited.However,thedraftingteam
recommendsthatthisdatacollectioneffortbeoutsideofandseparatefromthe
complianceprocess.

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Organization

GeneralComments:DukeEnergywouldliketotaketheopportunitytooffercommenton
theoverallprojectconcerningBALͲ002Ͳ2inconjunctionwiththerecentFERCNOPRissued
onNovember20,2014.FERCissuedaNOPRproposingtheapprovaloftheBALͲ001Ͳ2
standard(RealPowerBalancingControlPerformance).FERCcommentedinitsNOPRthat
furtherrevisionstotheBALͲ002standardshouldtakeintoconsideration,theimpactthe
revisionsmayhaveontheBalancingAuthorityACELimit(BAAL)inBALͲ001Ͳ2.DukeEnergy
agreeswiththeCommissionthatthepotentialimpactthatcompliancewithBALͲ002may
haveonBAALshouldbetakenintoconsiderationduringfurthermodificationstoBALͲ002,
andsuggeststhatthisprojectbetableduntilthefinalorderissuingtheapprovalofBALͲ
001Ͳ2hasbeenhandeddownbyFERC.

DukeEnergy

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

BalancingContingencyEvent:DukeEnergywouldliketoreͲstateitsconcernswiththe
proposeddefinitionofBalancingContingencyEvent.Originally,westatedthatwesought

33

Whilewemayagreewiththepremise,thecurrentstandardneedstobeeitherreplacedor
retiredsoonerratherthanlater.Thisrevisionaddressedtheproblemswiththeexisting
standardwhilekeepingessentiallythesamethinginplace.

FMPAsupportsthecommentsofDukeEnergy

ERCOTthanksyoufortheopportunitytocommentupontheproposedRevisionstoBALͲ
002Ͳ2andrespectfullysuggeststhat,asNERCcontinuesitsefforttomoveawayfromzero
defectstandards,RequirementR2berevisedasrecommendedabovetosupportthat
concept.ShouldtheEROwishtoprovideadditionalguidanceregardingthemixor
managementofContingencyReserves,itshouldconsiderthedevelopmentand
publicationofaReliabilityGuideline.

TheSDThasremovedthelanguagereferencedandmodifiedtherequirementtohavea
processforContingencyReserveintheirOperatingPlan.

averagedoveraclockhourisanonerous,purelyadministrativeobligationthatelevates
documentationoverreliability.Thus,ERCOTrecommendsthatRequirementR2berevised
assetforthabove.

Question1Comment

FloridaMunicipalPowerAgency

Organization

34

R1Rationale:IftheSDT’sintentistoeliminateanypotentialoverlapwithotherstandards,
thiswillnotbethecaseoncetheBAALisinplace.IfBALͲ001Ͳ2isapproved,therewillbe
anotherstandarddrivingaBAtotakecorrectiveactionwhenfrequencyishurting.Again,
wecautiontheSDTthatmovingforwardwiththeBALͲ002Ͳ2projectwithouttakinginto
considerationtheBAAL,couldresultinconflictingstandards.Inaddition,webelievethat
therearesituationswherecompliancewithBALͲ002mayhaveadetrimentalimpacton
Interconnectionfrequency.Forexample,astheDisturbanceControlStandard(“DCS”)
underBALͲ002ismeasuredeventͲbyͲevent,aBalancingAuthorityisrequiredtoreturnits

R1:Wewouldliketoofferourpreviouscommentonthisrequirementforthedrafting
team’sconsideration.DukeEnergysuggeststhefollowingrevisiontoR1.2:“1.2.A
ResponsibleEntityisnotsubjecttocompliancewithRequirementR1whenitis
experiencinganEnergyEmergencyAlertunderwhichContingencyReserveshavebeen
utilizedtoserveload.”WebelievetheintentoftheSDTwasfortheResponsibleEntityto
beexemptfromcompliancewithR1duringthoseinstanceswhereContingencyReserves
areutilizedtoserveload.DukeEnergyrequestsfurtherclarificationonwhatismeantby
thereferencetoactivateContingencyReservesunderanEnergyEmergencyAlert(EEA).

TheSDTisnottryingtosaythatBALͲ002providesfrequencymanagement.Weareonly
pointingoutthatsomepartsofBALͲ002caninfluencefrequencymanagement.

Background:IntherevisedbackgroundsectionoftheproposedBALͲ002Ͳ2,thesection
alludestofrequencymanagement,however,wefailtoseeanyrequirementinthis
standardpertainingtofrequencymanagement.

TheSDTdisagreeswiththisstatementandfeelsthatthepresentlanguageissufficient.
Also,thiscommentdoesnotappeartobesupportedbythemajorityoftheindustry.

clarificationonitemBoftheBalancingContingencyEvent(BCE)definition.ABCEshould
bepredicatedonadeviationinAreaControlError(ACE).Aswritten,weareunclearwhy
itemBisevenpartofthedefinitionbecausewebelieveItemBisredundantwithitem
A.a.ii.WefailtoseetheadditionalclaritythatItemBprovides,andcouldseewhere
questionscouldariseregardingthedifferencesbetweenthetwoitemsinthefuture.

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Organization

35

RegardingsubͲrequirement2.6,wefeelthatclarificationsareneeded.Aswritten
currently,itisunclearwhetheranentityhastoactuallyshedloadfor2.6toapply,orifyou
havetojustbepreparedtodoso.Thereareconcernsthatrequiringcompliance

Also,DukeEnergysuggestsareͲorderingofthesubͲrequirementsforR2.SubͲ
requirements2.4and2.5shouldbefirstandsecondonthelistofsubͲrequirementsbased
onthereasoningthattheywouldbethemostcommoninstances.

Aswritten,theauditablerequirementisforreservestoberestoredwithin90minutes.
Whilethecurrentlanguageofthestandardsuggestsitshouldbecompletedfaster,the
actualcompliancecheckpointisat90minutes.TheSDTalsoaddedRequirementR3to
provideadditionalclarity.

R2:DukeEnergyrequestsfurtherclarificationfromthedraftingteamonwhetheritsintent
wasforthestandardtobewordedinsuchamannertoallowforthewaivingofimmediate
restorationofreserves.IsittheSDT’sintenttoaffordanentitytheopportunitytowaitfor
aperiodof90minutes,beforerequiringtherestorationofreservestotakeplace?

InthedescriptionoftheEEALevel3,itstatesthatContingencyReservesarebeingusedto
serveload.Yourunderstandingoftheintentiscorrect.Thedraftingteammodifiedthe
languagetoprovideclarity.

ACEtozerowith15ͲminutesafteraReportableDisturbance(orbacktoitspreͲDisturbance
ACEvalueifthatvaluewasnegative).Sucharesponseinthefuturemaybeaproblemif
theReportableDisturbanceoccurswhenfrequencyisaboveScheduledFrequency,as
overͲresponserequiredbytheBalancingAuthoritytoensurecompliancewithBALͲ002
maycausetheBalancingAuthoritytobeaboveitshighBAALunderBALͲ001Ͳ2.Ifa
generationresourcewaslostinthemiddleofthenightduringaperiodofminimumload
concerns,numerousavailablegenerationresources,andhighInterconnectionfrequency,
BAALwoulddrivetheBalancingAuthoritytotakeappropriateactionoverareasonable
timeframe.DCSwouldnotconsideranyofthesefactorsbutwouldrequiretheBalancing
Authoritytostrictlycomply.ThisstrictcompliancewithBALͲ002couldhaveadetrimental
impactonInterconnectionfrequency.

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Organization

TheSDThasremovedthelanguagereferencedandmodifiedtherequirementtohavea
processforContingencyReserveintheirOperatingPlan

R2:Peakisconcernedthatusinganaverageclockhourmightallowentitiestotake
advantage.Forexample,ifanentityisdeficientthefirst30minutesbutsufficientthe
second30minutes,theaverageclockhourwouldbemetbutthefirst30minuteswould
beinanunreliablestate.

TheSDThasremovedthelanguagereferencedandmodifiedtherequirement.

36

R1.2:“AResponsibleEntityisnotsubjecttocompliancewithRequirementR1whenitis
experiencingaReliabilityCoordinatorapprovedEnergyEmergencyAlertLevelunder
whichContingencyReserveshavebeenactivated.”EOPͲ002Ͳ3.1speakstotheRC
initiating/declaringbutnotapprovinganEnergyEmergencyAlert.Itcanbearguedthat
parametersareinplacetomakeadecisiononapprovalbutneverthelessthereisno
mentionofapprovalsnordefinedapprovalprocesseswithinthestandard.Suggestionisto
revisefrom“approved”to“initiated/declared”toremainconsistentwithEOPͲ002Ͳ3.1.

General:BALstandardsshouldbedevelopedasagroupandnotindividually.

TheSDThasmodifiedtherequirementtohaveaprocessforContingencyReserveintheir
OperatingPlan.

Lastly,uponourreview,itcouldbearguedthatsomeofthesubͲrequirementsappearto
mirrorcloselyresponsibilitiesthatarealreadypresentinEOPͲ002.Wesuggestthatthe
SDTconsiderdelayingimplementationofBALͲ002Ͳ2sothatitbecomeseffectiveafter
EOPͲ011Ͳ1.

TheSDThasremovedthelanguagereferencedandmodifiedtherequirementtohavea
processforContingencyReserveintheirOperatingPlan

documentationtodemonstratethatyouwerepreparedtotakesomeaction,eventhough
saidactionnevertookplace,couldbeconsideredonerous.

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

PeakReliability

Organization

37

1. RequirementR1,Part1.1ͲReliabilityFirstsuggestsusingtheword“shall”insteadof
“will”tomakemandatorytheuseofthenotedCRForm1.Theterm“shall”indicatesa
dutyonthesubjectandisusedthroughouttheNERCStandardsinthismanner;inthis
casetheresponsibleentityhasadutytouseCRForm1,so“shall”isthemore
appropriateterm.ReliabilityFirstrecommendsattachingittothestandardsalongwith

ReliabilityFirstabstainsandoffersthefollowingcommentsforconsideration:

TheSDThasremovedthelanguagereferencedandmodifiedtherequirementtohavea
processforContingencyReserveintheirOperatingPlan

ThecurrentwaytheMeasureiswordedsupportsthispurposedchange.

InregardstoR2.6:InanEnergyEmergencyAlertLevelunderwhichtheResponsibleEntity
nolongerhasrequiredContingencyReserveavailableprovidedthattheResponsibleEntity
hasmadepreparationsforinterruptionofFirmLoadtoreplacetheshortfallof
ContingencyReservetoavoidtheuncontrolledfailureofcomponentsorcascading
outagesoftheInterconnection.Forthisexemptiontoapply,thepreparationsmustbe
initiatedwithin5minutesfromthetimethattheEnergyEmergencyAlertLevelis
declared.SouthernagreesthataBAshouldnotberequiredtomaintainContingency
ReservesduringanapplicableEnergyEmergencyAlertlevel(forSouthernthatwouldbe
anEEA3).Ourconcerniswithhowthefollowingsentenceisphrased“Forthisexemption
toapply,thepreparationsmustbeinitiatedwithin5minutesfromthetimethatthe
EnergyEmergencyAlertLevelisdeclared.”Werecommendadifferentapproachsothatit
reads,“Forthisexemptiontoapply,thedeficientBAmustbeabletoexecuteinterruption
ofFirmLoadtorestoreACEwithintheContingencyEventRecoveryPeriodtimeframe”.
TherationalebehindthischangeisifadeficientBAcanrecoverACEwithinContingency
EventRecoveryPeriodvialoadshedthisshouldbeanacceptablepracticebuttheymust
havetheabilitytoexecutecompletelythisactionwithintheContingencyEventRecovery
Periodtimeframe(e.g.15minutes).Southernagreeswiththedraftingteamthatinan
EEA3aBAshouldbeabletoconsiderloadshedasaviablepracticetomaintainACEand
notberequiredtoreͲestablishContingencyReservesbysheddingloadpreͲcontingency.

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

ReliabilityFirst

SouthernCompany:SouthernCompany
Services,Inc.;AlabamaPower
Company;GeorgiaPowerCompany;
GulfPowerCompany;MississippiPower
Company;SouthernCompany
Generation;SouthernCompany
GenerationandEnergyMarketing

Organization

38

Whiletheoreticallypossible,thisoperatingpracticewouldsubjectanentitytoviolationof
oneorbothrequirementsifaneventoccursduringtherampperiod.(Inotherwords,one
baddayanditwillneverhappenagain.)

Fromafinancialperspective,thereisnothinginthisrevisionstoppingaBalancing
AuthorityfromhavinglessContingencyReservesthantheirMostSingleSevere
Contingencyduringthelast20to30minutesofeverysteeploadpickuphoureveryday.



Seattlewouldsupportthedraftmore,however,iftheterm"clockhouraverage"was
replacedwith"instantaneousvalue"throughouttheStandard.UsingHourlyaverages
placesentitiesinthepositionwheretheymaybeincentivizedtohavelessContingency
ReservethantheircurrentMostSingleSevereContingencyforlargepercentagesofkey
operatinghours.

SeattleCityLightsupportsBalancingAuthoritieshavingtheflexibilitytouseContingency
Reservetorespondtootherreliabilityeventsandvotesaffirmativeforthisballot.

TheSDThasmodifiedtherequirementandthereforemademodifiedthemeasure
accordingly.

2. MeasureM2ͲThenewlyincludedsecondparagraphwithinMeasureM2readsmore
asanexceptiontotherequirementanddoesnotbelongasameasure.Itappearsto
beguidancetoanauditorandshouldmoreappropriatelybeplacedinanRSAW.
Furthermore,ReliabilityFirstdoesnotwanttoencouragemissingdataasareasonfor
notperformingthecalculationandbelievesanyorasmanyvalidsamplesofthe
ContingencyReserveshouldbeincludedintheclockhourandshouldnotbeexcluded
fromtheevaluation.ReliabilityFirstrecommendscompletelyremovingthesecond
paragraphwithinMeasureM2fromthestandard.

TheSDTisattemptingtoprovideforconsistencyinreporting.

thefollowingchangeforconsideration:“TheResponsibleEntityshalldocumentall
ReportableBalancingContingencyEventsusingAttachment1ͲCRForm1.”

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

SeattleCityLight

Organization

TheSDTagreesandhasmadethechange.

RegardingtheRationaleforRequirementR1,shouldReportableAreaControlErrorbe
ReportingACE?ReportingACEisintheNERCGlossary,ReportableAreaControlErroris
not.

TheSDTislookingintothispossibility.

39

IntheNERCGlossary,ReportableDisturbanceisdefinedas“AnyeventthatcausesanACE
changegreaterthanorequalto80%ofaBalancingAuthority’sorreservesharinggroup’s
mostseverecontingency.Thedefinitionofareportabledisturbanceisspecifiedbyeach
RegionalReliabilityOrganization.Thisdefinitionmaynotberetroactivelyadjustedin
responsetoobservedperformance.”ThedefinitionofReportableBalancingContingency
Eventshouldberevisedtoincorporatethisdefinition,andshouldbemadetoread”...(i)
ReportableDisturbance,or...”.Withthisrevision,whenBALͲ002Ͳ1isretiredthedefinition
ofReportableDisturbancecanberetiredaswell.

Yes,ifaneventtakeslongerthanaminutetounfold,itmakesthemeasurementprocess
impossible.Thereforethestandardonlycoversthoseeventsthatmeettheexact
definitionofReportableBCE.ThesetofBalancingContingencyEventswouldbydefinition
beeitherequaltoormorethanlikelygreaterthantheReportableBCEset.

ThereisapossibleinconsistencyinthetermsBalancingContingencyEvent,and
ReportableBalancingContingencyEvent.BalancingContingencyEventisdefinedas“Any
singleeventdescribedinSubsections(A),(B),or(C)below,oranyseriesofsuchotherwise
singleevents,witheachseparatedfromthenextbylessthanoneminute...”Reportable
BalancingContingencyEventisdefinedas“...(ii)theamountlistedbelowforthe
applicableInterconnection,andoccurringwithinaoneͲminuteintervaloftheinitial
suddendeclineinACE...”Byitsdefinition,theBalancingContingencyEvent,inthe
extreme,isanunlimitednumberofsingleevents,aslongastheyareseparatedbyless
thanoneminute.IsitintendedforaReportableBalancingContingencyEventtoonly
encompasswhathappensinthefirstminuteasitisworded?

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

NortheastPowerCoordinatingCouncil

Organization

a.Forexample,Part1.3(ii)doesnotincludeanexemptionfordeploying
ContingencyReserveforaContingencythatisnotaNERCdefinedBalancing
ContingencyEvent.R2doeshaveanexemptionforthisandotherscenarios.The
term"sudden"beingincludedinthedefinitionofaBalancingContingencyEventis

40

2)Therearecontradictoryportionsofthestandardwhichwouldleaveoperatorsconfused
andagainleadtocomplianceexposure.

1) Theproposedstandardcontinueswithseveral“compliancetraps”whichwillhamper
operators’effectiveuseofContingencyReservestomitigatereliabilityproblems,and
thencouldcausecomplianceexposureduetoauditorinterpretation.Forexample,R1
wouldrequireaBAtodeployatleastsomeofitsreservesinordertodeclareanEEA
exemptioneveniftheremaynotbeanimmediateneedtodoso.

TheSDThasmodifiedthelanguageandbelievesthatyourconcernhasbewen
addressed.

Additionalcomments:

TheSDThasmodifiedtherequirementandthereforemademodifiedthemeasure
accordingly.

InRequirementR2,andMeasureM2“Firm”shouldnotbecapitalized.“FirmLoad”isnot
intheNERCGlossary.ItshouldberevisedtoreadfirmLoad.

TheSDTagreesandhasmadethechange.

MeasureM1shouldberevisedtoread“...thatdemonstratescompliancewithParts1.2
and1.3.”.

TheSDTagreesandhasmadethechange.

InthesecondparagraphoftheRationaleforRequirementR1thatreads”...asdescribedin
R1.3below...”shouldberevisedtoread“asdescribedinPart1.3...”.

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Organization

3)ThereareseveralproblemswiththedefinitionsincludingdefinitionsofMostSevere
SingleContingency(MSSC),ContingencyEventRecoveryPeriod(CERP),andBalancing
ContingencyEvent(BCE).

41

Thedraftingteamdisagreeswiththeneedtoaddasentencetothedefinitionof
ReportableBCE.ThestartingtimeofaneventisdeterminedbythedefinitionofPreͲ
ReportingContingencyEventACEValue.

Whiletheexampleyouprovideworksverywellforthesingleentitythatitcovers,
thistypeofstructureisnotlikelytoworkforanationͲwidestandard.Thestandard
coversentitiessuchasrelativelysmallBalancingAuthoritieslikeLADWPtoverylarge
entitiessuchasPJM.ThereforeastatedMWamount,orevenastatedpercentage
wouldnottreatallentitiesevenlyorfairly.Thedraftingteamsupportstheconcept
thateachentitycouldprovidefurtherdefinitionthroughwrittenproceduresto
clarifyhowthatentityimplementstheirprogram.

Theterm“sudden”isusedinthedefinitionofawidecategory.Thiscategorymaybe
usedtorefinetheneededrecoveryforaReportableBalancingContingencyEvent
underR1intheproposedstandard.Thedraftingteambelievesthatasstructured,
theterm“sudden”doesnotneedfurtherdefinitionasanydefinitivedefinition
wouldbesomewhatarbitraryandpossiblyillͲfittingforonesizeentitywhile
perfectlyreasonableforanother.

b.R1doesnottreatsubsequentContingenciesinaconsistentmanner,againrelated
totheterm"sudden"beingincludedinthedefinitionofaBalancingContingency
Event.SeethefirstscenarioinAttachmentA(sentbyEͲmailtoDarrelRichardson).

TheSDThasremovedthelanguagereferencedandmodifiedRequirementR2tohavea
processforContingencyReserveintheirOperatingPlan

thesourceoftheproblem.SeethesecondscenarioofAttachmentA(sentbyEͲmail
toDarrelRichardson).

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Organization

42

This,togetherwiththerecoveryprovisioninR1(resultsͲbasedrequirement)andthe
provisioninRequirementR6andAttachment1ofEOPͲ011Ͳ1(whichdefinesEEAlevels)
wouldcollectivelytakecareofmanyoftheconditionslistedintheproposedRequirement
R2includingactivemonitoringoftheamountofreservetomeettheContingencyReserve

AnalternativesuggestedrewordingofR2:R2.TheResponsibleEntityshall
developoperationalplansthatprovidesufficientContingencyReserve
consideringallothereventsthatmayreducethisamount.

R2.TheResponsibleEntity,ifdeficientinContingencyReserves,has90
minutestorestore.IftheResponsibleEntityexperiencesaReportable
BalancingContingencyEventduringthistimeanadditional15minutesare
allotted.”

b.Muchlesscomplicatedlanguageisproposedhere,basedontheoriginalNERC
Policy1.SuggesttherevisionofR2toread:

a.R2isfarmorecomplexthannecessary,isunclear,andcontainspotentialfor
gaming.

4)RegardingR2:

b.BCEisunclearwithregardtobothgenerationandtransmissionevents.(Also
considerifA.ItembwithintheBCEdefinitioninsteadreferredtoanunplanned
changeinACEasopposedtoanunexpectedchangeinACE.)

Ifloadisdroppedconcurrently,thesizeoftheeventisthesizeofthegenerator,the
loadthatdropsisreserveforthateventandtheresponserequiresonlyanamount
ofadditionalreserveoverandabovethenetamount.Itshouldbepointedoutthatif
thisloaddoesnotdropforthelossofanotherunit,theactualamountofreserve
neededmaybemorethanthenetamount,dependingonthesizeofthenextlargest
contingency.

a.MSSCdoesnotincludeconcurrentlydroppedloadwhichmaycauseaBalancing
AuthoritytocarryextraContingencyReservebeyonditsactualMSSC.

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Organization

g.RequirementR2createsanartificialincreaseinreservesinordertomaintainan
amountoverͲandͲabovethatrequiredbythestandardtomeetnonͲDCSoperational
events,therebyincreasingcoststoratepayersfornoincreaseinreliability.

f.R2alsocausesBAstocarrymuchhigherContingencyReservesthannecessaryduring
thelatterportionsofthehourinorderto“makethenumberscomeoutright”iftheyare
belowMSSCinthebeginningofthehour.

e.RequirementR2mayproduceaperverseincentive.ABAmayletitsACEremain
negativetokeepthereservemonitornumbersaboveMSSC.Also,withoutanumberof
"gracehours"perquarter,theremaybeasusceptibilitytoloadsrunningunexpectedly
highneartheendofaClockHour,causingaminisculeshortfallthatresultsinan
occasional"nuisance"complianceviolation.

43

d.RequirementR2continuestonotincludeanumberof“gracehours”perquarter,as
requestedinsomeindustrycomments.Itmayhaveaneteffectofincreasingtheamount
ofavailablecontingencyreservetosomeBAswhichmaymarginallyincreasereliability.
However,thisneedstobebalancedagainstincreasedoperatingcostsduetocarrying
morereserve.

TheSDThasremovedthelanguagereferencedandmodifiedRequirementR2tohaveaprocessfor
ContingencyReserveintheirOperatingPlan

c.ThelanguageinPart2.2regardingOperatingInstructionappearstoallowoperating
personneltocreateexemptionsfromR2atwill.

WebelievethistogetherwiththerecoveryprovisioninR1wouldtakecareofmanyofthe
conditionslistedintheproposedRequirementR2.

requirement.R2aspresentedinthisdraftrequiresaBAtodemonstratethatitmaintains
ContingencyReserve,averagedovereachClockHour,greaterthanorequaltoitsaverage
ClockHourMostSevereSingleContingency,exceptundercertaincircumstances.Ifthe
SDT’sintentistoensurethataBAconsidereventsotherthanMSSCthatcouldreducethe
amountofreserve,thentomeetthisintentwesuggestreplacingR2asshownpreceding.

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Organization

Entitiesthathavetoshedfirmcustomerload(becauseloadcannotbeshedfast
enough)tomaintainreservestomeetcompliancewiththisrequirementisnotan
actionthatshouldbetakenforreliability.

7)Part1.3andR2shouldbecognizantofunexpectedlossofreservewithoutitbeing
accompaniedbyalossofpowerbeingdelivered.Inthelastposting,weexpresseda
concernwiththeterm“suddenloss”(seebelow).Weareunabletofindanyresponsein
44

6)WhentheexemptioninPart2.6becomesrelevant,itmostlikelywilloccurwithinthe
middleofaClockHour.Itisnotclearif"instantaneousvaluesshowingreserves"refersto
thesumofContingencyReserveavailableplusFirmLoadthatcanbeshed.

5)ThelastsentenceofmetricM2whichsplitsaClockHourintosubͲperiodsisdifficultto
followandseemstoaddunnecessarycomplexityindeterminingcompliance.

oWhentheResponsibleEntityisusingitsContingencyReserveforaperiodnotto
exceed90minutes,toresolvetheexcedanceofaSystemOperatingLimit(SOL)or
InterconnectionReliabilityOperationLimit(IROL).

k.Toincludetheremainingconditionsthatarenotalreadyaccountedforunderwhicha
BAmaynotbeabletomaintaintherequiredamountANDduringwhichanMSSCevent
occurstherebyrenderingaBAunabletomeetrequirementR1,thenthefollowingbulleted
itemmaybeaddedunderPart1.3inR1:

j.Inourpreviouscomments,wefoundRequirementR2confusingandthatthe
requirementitselfwasunnecessaryforsolongastheBAmetrequirementR1.HavingR1
thatrequiresaBAtomeettheACErecoveryrequirementfollowinganMSSCeventwould
sufficetodrivetheproperbehaviorofsecuringadequatereservearoundtheclock(except
thoseconditionslistedinR1).IfandwhenacontingencyoccursandtheaffectedBAdoes
nothavesufficientreservetorecoverACE,thenitwillfailR1whereasifR2aspresentedis
retained,thenaBAcouldfailbothrequirements.ThereisnoneedforhavingR2to
supportR1,whichcanresultindoublejeopardy.

i.

h.R2willencourageoperatorstonotdeployreserveswhenneededforreliabilityinorder
tomeetcompliancewiththisrequirement,whichcouldbedetrimentaltoreliability.

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Organization

45

R3.Ifnoresourceislost,ContingencyReservemustequalanentity’sMSSCforeach
datapointbaseontheentity’sSCADAscanrate.

R2.ReplaceanyContingencyReservewithin105minutesofthelossofaresource

R1,CorrectyourACEwithin15minutesofthelossofaresource

Thestandardiscomplexbecausetheissuesweareaddressingaremanyandinterrelated.
Asimplestandardwouldbe:

Tosummarize,theJanuary2015versionofBALͲ002Ͳ2couldbeimprovedbyproviding
betterclaritywithinthedefinitionsandmakingsimplificationsthatyieldamore"operatorͲ
friendly"standard.Thereisaconcernthatthecomplexityandnuancesoftheproposed
standardinsomecircumstancescouldbeadistractiontotheoperatorwhenmore
importantreliabilitytasksneedtobeperformed.

TheSDThasremovedthelanguagereferencedandmodifiedRequirementR2tohavea
processforContingencyReserveintheirOperatingPlan

theSummaryConsiderationreportthataddressesthiscomment.Pleaseconsiderthese
commentsandprovidearesponse.ABalancingContingencyEventisvaguelydefinedasa
“Suddenlossofgeneration...”or“suddendeclineinACE...”.Theword“sudden”is
imprecise,andshouldbeclarified.Wesuggestthatthestandardbecleareraboutdefining
thestarttimeforaReportableBCE.WesupportdefinitionslikethatusedinNPCC
Directory5section5.17whereitsaysthatthestartofaneventhasoccurredwhena
specificXamountofMWsarelostinaspecificYamountoftime.Therefore,wesuggest
thatthedraftingteamaddprecisionindeterminingminuteT+0foraneventbyaddingthe
followingsentence(orsomethinglikeit)totheReportableBCEdefinition:“Followingthe
resourcefailure,theReportableBCEstartingtimeisdefinedasthefirstchronological
rollingoneminuteintervalthatmeetsthereductioninresourceoutput(s)criteriastated
herein.”TheSDT’sresponsetocommentdoesnotappeartoaddressthisparticular
comment.WeasktheSDTtopleaseprovidetherationaleastowhythissuggestionwas
notadopted.

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Organization

46

AssigningaMediumVRFtobothR1andR2isnotappropriateͲthereliabilityimpactofnot
havingtherequiredamountofreservesdoesnotseemcomparabletothereliability
impactofnotrecoveringACEafterareportableBCE.TheVRFforR2shouldbelowerthan
R1.IfR2cannotberevisedassuggestedbyPJM,analternativetotheaverageClockHour
measurementperiodshouldbeprovided.IfreservesdipbelowtheMSSClateinaClock
Hour,itisdoubtfulifaREcouldactintimetoresolvetheshortfall.Also,whatisthe

TheSDTdoesnotcompletelyagreewithyourcomment.Thisassumptionispossiblefor
someRSGsbutmaynotbepossibleforallRSGs.

ItisnotclearhowthecomplianceexemptionsinR1.2andR2.6foraResponsibleEntity
experiencinganEEAwouldapplytoaRSG.SinceanRSGcannotrequesttheRCtodeclare
anEEA,itappearstheRSGwouldberequiredtomaintainMSSClevelreservesregardless
oftheEEAstatusofitsmemberBAs.ItalsoappearstheRSGcouldbefoundnonͲ
compliantwithbothR1.2andR2.6simultaneousl.Wesuggestthatwhileamemberofa
RSGisinanEEA,itsMSSCandContingencyReserveRequirement(thememberBA’s
reserveobligationtotheRSG)areremovedfromtheRSG.ThereconfiguredRSGwould
continuetomaintaintheRSGbasedonthenewMSSCandtherevisedassignmentofCRR
amongthenonͲEEAmembers.TheRSGwouldremaininthisconfigurationforthe
durationofthememberBA’sEEA.

ThesecommentsaresubmittedonbehalfofthefollowingPPLNERCRegisteredAffiliates:
LG&EandKUEnergy,LLC;PPLElectricUtilitiesCorporation,PPLEnergyPlus,LLC;PPL
Generation,LLC;PPLSusquehanna,LLCandPPLMontana,LLC.ThePPLNERCRegistered
Affiliatesareregisteredinsixregions(MRO,NPCC,RFC,SERC,SPP,andWECC)foroneor
moreofthefollowingNERCfunctions:BA,DP,GO,GOP,IA,LSE,PA,PSE,RP,TO,TOP,TP,
andTSP.ThePPLNERCRegisteredAffiliatessupportthecommentsprovidedbyPJM.In
addition,wesubmitthefollowingcomments:

Thiswouldnotprovidethenecessaryinformationtobeabletoconsistentlydefine
compliancewithinthestandardandtodatehasnotbeensupportedbythemajorityofthe
industry.

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

PPLNERCRegisteredAffiliates

Organization

47

Thisconcernisheightenedbytheaddition(effective4/1/2015)oftheexpression,“and
discourageresponsewithdrawalthroughsecondarycontrolsystems,”totheNERC
GlossarydefinitionofFrequencyBiasSetting.Thischangeechoesthestatement,
“appropriateouterͲloopcontrols(distributedcontrols)settingstoavoidprimaryfrequency
responsewithdrawal,”intheNERCResourceSubcommittee’s2013Eastern
InterconnectionFrequencyInitiativeWhitepaper,”and“RelatedouterͲloopcontrols
withintheDCS,aswellasapplicablegeneratingunitorplantcontrols,shouldbesetto
avoidearlywithdrawalofprimaryfrequencyresponse,”inNERC’s2/5/2015Industry
Advisory,GeneratorGovernorFrequencyResponse.”Implementationofappropriate
governortimedelaysanddroopsettingsconstitutesawellͲdefinedandtechnologically
justifiedformofGOinvolvementinfrequencyresponseimprovement,buttheterm
“responsewithdrawal”isvagueandcouldcauseBALͲ002Ͳ2tobemisconstruedas

ThisstandarddoesnotallowBAstoimposedemandsuponotherparties.ItallowsaBAto
providethereservesfromessentiallyanyresourcethatmeetsthedefinitionandintentof
theresponseneededforcompliance.

BALͲ002Ͳ2directlyappliesonlytoBAsandReserveSharingGroups,butitstatesinthe
definitionofContingencyReservethatthecapacitymandated,“maybeprovidedby
resourcessuchasDemandͲSideManagement(DSM),InterruptibleLoadandunloaded
generation.”Thatis,BAscanfulfilltheirBALͲ002Ͳ2obligationsonlybyimposingdemands
ontheseotherparties,andwewouldliketoknowupͲfrontwhattheywillbe.

TheSDThasremovedthelanguagereferencedandmodifiedtherequirementtohavea
processforContingencyReserveintheirOperatingPlan.TheSDTfeelsthatneitherofthe
requirementswoulddefinitelycausecascadingoutagebutthereisthepossibility.Forthis
reasontheSDTbelievesthatamediumVRFiscorrect.Thisalsoagreeswiththecurrent
similarrequirementsVRFs.

reliabilitybenefitofanREactingtoincreaseitsreservesiftheshortfalloccursearlierin
thehour?Itdoesn’tseemtheaverageClockHourmeasurementperiodprovidesanRE
muchflexibilityincomplyingwithR2nordoesitimproveBESreliability.Arollinghourly
averageormultiͲClockHouraveragewouldbeanimprovement.

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Organization

MISO

48

ThedraftingteamwillonlypointtotheexistinginterpretationandNOPRproposedby
FERCtoremandtheinterpretationandstatethatwhileMISOmayoperatebasedontheir
understandingoftraditionandhistory,thereisobviouslyacleardisconnectbetweenthe
regulatoryinterpretationofthecurrentstandardandtheindustry’sinterpretationofthe
existingstandard.IFtheregulatedandregulatorscannotagreeonwhatthestandardsays,
thenitobviouslyneedscorrected.Thedraftingteambelievesthattakingastandardfrom
6requirementsto2requirementswhileessentiallycontinuingtooperateashistorywould
showhasbeendoneisnotasignificantchange.

ThecurrentBALͲ002iswellunderstoodbysystemoperatorsandperformanceasposted
ontheNERC“AdequateLevelofReliability(ALR)Metrics”websitehasbeenstellar.The
draftoutforcommentisnoteasilyunderstood,addscomplexity,andwilllikelyincrease
customercostfornodiscernablereliabilityvalue.

WeunderstandthattheteamistryingtomeettheirinterpretationofOrderNo.693
directives.WerespectfullysubmitthatmuchofwhattheFERCdirectedmaybemootas
thedirectivesrelatedtoprimary,secondary,andtertiarycontrol,havebeenmetbyother
standardsprojects.ThisisparticularlytrueconsideringtheequallyeffectiveR2(Balancing
AuthorityACELimit,BAAL)inBALͲ001Ͳ2andaperformancebasedFrequencyResponse
Standard.

Wecommendthedraftingteamontheeffortcommittedtothisprojectandappreciate
theimprovements.Wealsoappreciatethevariousobjectivestheteamistryingtomeet,
butbelieveitistimetostepbackandensurewearemovinginadirectionwhereNERCis
tryingtogowithclearer,resultsͲbasedstandards.

TheSDTbelievesthatthereissomeconfusionhere.Forclarity,ContingencyReserve
responsehasnothingtodowiththeissueraisedinyourcomment.ContingencyReserve
responseismeasuredovera10Ͳ15minuteperiod,notthetimeperiodsdiscussedinthe
referenceddocument.

authorizingBAstodemandnew,frequencyresponseͲenhancingservicesfromGOsasa
regulatoryrequirementratherthanobtainingthemthroughmarketmechanisms.

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Organization

5]Forthoserequirementsthatareultimatelyproposed,isthereawaytokeepthem
simpleandeasytounderstandasopposedtobeingoverlyprecise[Forexample,ifthere

4]Theextenttheremaining693directiveshavebeenmetbyotherstandardsprojects.
[WebelieveBAALaddressestheCommission’sconcernsfordetectingandrespondingto
significanthighorlowfrequencyevents,addressestheconcernaboutperformanceto
individualevents,andisaperformanceͲbaseddoubleͲconfirmationofsecondaryand
tertiaryreserves]

49

3]SincetherearenowperformancebasedBAALandFRSinplace,couldwenotactually
simplifythecurrentDCS?[RetainacleanerversionofthecurrentR1,andasimplerR2that
requirespresentingreservevaluestoBAandRCwithappropriatealarmpoints]

2]WhatconstitutesacontinentͲwidecontingencyreservepolicy?[Webelievethepolicy
couldbemetbydevelopingsimpledefinitionsforthevariouscategoriesofoperating
reservesasanycanbeusedtomeetDCSortheotherBalancingStandardsinrealtime.
ThepolicyshouldstatethattheBAperformsananalysistodevelopwarningandalarm
pointsfortheiroperatorsforthereservesneededtomeetBALͲ001,BALͲ002,andBALͲ
003.HavingBAsprovidethisdatatoinrealtimetotheirReliabilityCoordinatorswould
addreliabilityvaluetotheEEAandotherEOPprocesses.Finally,aguidelinesdocument
onreservesapprovedbytheNERCOperatingCommitteecouldbepartofthispolicy]

Thedraftingteamagreeswiththisposition.Wealsobelievethatthisiswhattheexisting
standardsays.Clearlyourregulatorsdonot.Bothindustryandourregulatorsagreethat
thisproposedstandarddoessaythat.

1]WhatshouldbetheobligationoftheBalancingAuthorityforevents>MSSC?[We
suggestthatsucheventsarereportedtodemonstratebesteffortsweremade,but
complianceisnotassessed.TheBAisstillaccountableforBAAL.Finallythereare
backstopstandardsasloadsheddingismandatedintheEOPandIROstandardsfor
harmfulfrequencyconditionsandIROLexceedances]

Ifthestandardeffortreachesanimpasse,itmaybetimetoholdatechnicalconferenceto
getresolutiononafewkeyitems:

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Organization

Theproposedstandarddoesnotrequiretheactivationofaspecificreserveproduct,it
requirescorrectingACEwithinthespecifiedtimeperiod.Thereisnorequirementforany
entitytorespondinaspecificmanner.

50

WeagreewithcommentssubmittedbytheIRCͲSRCandMROͲNSRFasappliedtothe
currentdraft.Thequestioniswhethertocontinuetoadjustthecurrentdraftormake
surewearecreatingasolutionthatisrelativelysimpletoapplyandprovidesreliability
value.Ifwecontinuedownthecurrentpathforthestandard,wehavetwoprimary
concerns.Ourfirstconcernisthattheloweringofthethresholdto900MWintheEast,
coupledwiththeproposedchangefromquarterlyaverageperformancetoindividual
eventperformance,willincreasecustomercostsfornodiscernablereductioninreliability
risk.BothDCSperformance(ALRstatistics)andfrequencyperformance(NERCResources
Subcommitteeminutes)showfrequencyperformanceismorethanadequate.Asnoted
byChairwomanLaFleuratNERCBoardmeetings,weshouldconsiderthereliability
benefitsofastandardvs.itscosts.Costswillincreasewiththelowerthresholdforour
customers.BecausetheinterconnectionisoverͲbiased(ACEoverstatesresourceloss)and
dispatchersoperateconservatively,ouroperatorswilllikelydeploysetͲasidecontingency
reservesforanylossover750MWratherthanwaittodoubleͲchecktheeventsize.(An
eventisdefinedbythesizeoftheresourcelost,notthechangeinACE.)Thiswilllikelyadd
scoresofcontingencyreservedeploymentcaseseachyearforsituationsthatcouldlikely
bemetbyotheronͲlinereserves.

TheSDTisnotsureweunderstandhowyouaresuggestingwesimplifytheproposed
standard.TheSDThasmadesignificantmodificationstotherequirementswhich
hopefullyhasaddressedyourconcerns.

areexclusionsinarequirement,ratherthantryingtocalculatereserverecoverytothe
minute,excludethehourwhenthesituationoccursandthefollowinghour(s),thenumber
ofhoursdeterminedbytheextentcontingencyreservesweredepleted)?

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Organization

Anotherreasonforourconcernisthatthiscommodityrequirementisbeingproposed
withoutanydatatosupportwhatactuallyiscarriedhourtohouracrossthe
Interconnectionsandtheextentoperatorsdrawonthesereservestokeeptheirsystem
balanced.IfR2isretainedasproposed,webelievethatitshouldbea“positioning”
requirement,notazeroͲdefectrequirement.Asproposed,eithercustomercostswill
increaseorreliabilitywillbenegativelyimpacted.Theonlywaytohavemorethan100%
reservesallthetimeinnormaloperationsistocarrywellmorethan100%reservesasa
basisofoperationsorchoosenottodeployreservesfornonͲreportableeventsanddraw
51

OursecondmajorconcernwiththecurrentpostingforcommentisthatR2goesbeyond
theoriginalintentoftheDCS.Thereasontherearenomeasuresforthisrequirementin
BALͲ002Ͳ0isthatitwasneverintendedtobeacommoditystandard.Thepredecessorto
DCSwasPolicy1,whichhadguidelinesonoperatingreserves.ThefirstDCSwasoneof
NERC’sfirstperformanceͲbasedstandardsandexistedpriortotheERO.Theintentwasto
retaintheconceptoftheguidetoplantohaveacertainamountofreserves.The
measuresofsuccessweretomeetCPSandDCS.DCS’intentwastorespondquicklytoall
largeevents,withperformanceevaluatedonevents80%Ͳ100%ofMSSC.Theintentofthe
90minutereservereplenishmentwastogetreadyforfutureevents(meaningyou’dbe
heldforcompliancetothestandardforevents90minutesthereafter).

WealsorecommendthatNERCretainsthequarterlyreporting.IndividualcasesofnonͲ
compliancecanbetalliedintheformtoachievetheFERCdirective,butwebelieveitis
importantthatEnforcementassessescompliancebaseontheaggregateperformanceof
theBAorRSG,notjustspotobservations.

TheSDTdoesnotseethesignificanceinchangingfroma900MWto1000MWreporting
threshold.TheSDTdoesnotbelievethatthelowerthresholdwillplaceanyundueburden
onthereportingofevents.TheSDTwouldwelcomeanyinformationthatyoucould
providetojustifythesuggestedmodification.

Finally,itshouldbenotedthatthefrequencychangefroma900MWlossintheEastis
barelybeyondthechangefromaTimeErrorCorrection.Ourrecommendationisthatthe
standardusesthelesserof80%ofMSSCor1000MWfortheEast.

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Organization

52

1. Theminimumrequirementforcomplianceis100percentsoanyfailuretorespond
causesanonͲcompliance.Thequestionthenishowisafinedetermined?Shoulditbe
basedonthepercentageofeventsforwhichcompliancewas/wasnotobtained,the
percentageoffailedresponse(i.e.totalresponseneededforalleventswas1,000,
responsereceivedwas950)
2. Quarterlyreportingaveragescanmovebasedonthenumberofreportableeventsina
quarter,thesizeofreportableeventsorothervariablethatarguablehavenobearing
ontheimpacttotheBESofanentity’sfailuretomeettheresponserequirement.
Dependingontheanswertothefirstissue,thismayormaynotbeareasonable
metric.Justbecauseithasbeenusedforcompliancepurposes,thatdoesnotmeanit
isareasonablemeasureofreliabilityorimpacttoreliability.

Individualeventreportingversusquarterlyreportingincludesthefollowingpoints:

Additionally,inamultiͲBAInterconnection,theoddsthattheInterconnectionwouldbe
deficientinReserveswitha99%BAstandardareastronomical.InasingleͲBA
InterconnectiontherearebackstopsintheEOPandIROstandards.BALstandardsarefor
normaloperations.Otherstandardsprotectagainstevents>NͲ1.Finally,webelieve
thereshouldbeasinglequarterlyreportforR1andR2.TheR1portionshouldbe
simplifiedtobeverysimilartotoday,toincludereportingofevents>MSSC(butnotpart
ofcomplianceevaluation).ThequarterlyR2portionofthereportshouldhavethenumber
ofnonͲexcludedhourstheBAhadreserves<MSSCandanidentifierwhichhourswere
excludableunder2.1through2.6.

onfrequencybiastokeepreservesavailable.Whiletheproposalprovidessome
exclusions,therequirementshouldstartonthebasisthattherewillalwaysbesome
variabilityandunforeseennonͲconsequentialeventsthatwillrequirereservedeployment.
Ifretained,wesuggestR2shouldrequirecontingencyreserves>100%MSSCfor99%ofall
applicablehours.ItshouldbenotedthatjustbecauseaBAhaslessthanMSSCinonehour
infourdays,doesnotmeanthatithadzeroreservesinthathour.

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Organization

53

TheSDTdoesnotseethesignificanceinchangingfroma900MWto1000MWreporting
threshold.TheSDTdoesnotbelievethatthelowerthresholdwillplaceanyundueburden

TheNSRFisconcernedthattheloweringofthethresholdto900MWfortheReportable
BalancingContingencyEventintheEasternInterconnection,coupledwiththeproposed
changefromquarterlyaverageperformancetoindividualeventperformancewillincrease
customercostsandsignificantlyincreasecomplianceexposurefornodifferencein
reliabilityrisk.BecausetheinterconnectionisoverͲbiased(ACEoverstatesresourceloss)
andoperatorsoperateconservatively,theywilllikelydeploycontingencyreservesforany
lossover800MW.Ourrecommendationisthatthestandardusesthelesserof80%of
MSSCor1000MWfortheEasternInterconnection.

Wecommendthedraftingteamontheimprovementsmadesincethelastposting.Below
areourconcernsandrecommendationsforimprovement.

354.First,theCommissiondirectstheEROtodevelopamodificationtothe
ReliabilityStandardrequiringthatanysinglereportabledisturbancethathasa
recoverytimeof15minutesorlongerbereportedasaviolationoftheDisturbance
ControlStandard.ThisisconsistentwithourpositionintheNOPRandNERC’s
positioninresponsetotheStaffPreliminaryAssessmentoftheRequirementsin
BALͲ002Ͳ0,andwasnotdisputedorcommenteduponbyanyNOPRcommenters.

FromOrder693

Theindividualeventreportingmovesthecomplianceprocesstomeetthealreadyused
enforcementprocess.ThisalsosatisfiesaFERCOrder693directive.

Ifweassumethatthetotalresponseprovidedinthequarterdividedbythetotalresponse
requiredinthequarter,onlytheMWsfailedtobedeliveredmatters,nottheamountof
timeafterwards.Therefore,anindividualeventevaluationprovidesforamuchbetter
meanstodeterminetheimpacttoreliabilityfromasinglefailureasopposedtoaquarterly
mishmashofallevents.Thedraftingteambelievesthatwhileaquarterlyreportmay
providegooddatafortrendanalysis,itisapoormeanstodeterminecompliance.

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

MROͲNERCStandardsReviewForum

Organization

NERCistryingtomoveawayfromzerodefectstandards.Thisstandardshouldbe
structuredtosupportthatconcept.

TheVSLsshouldbebasedonthenumberofhoursthatreserveswere<MSSCandnot
excluded:oLow:2orfewerhours(represents0.09%ofthehoursinthequarter)o
Medium:3Ͳ5hoursoHigh:6Ͳ9hoursoSevere:10ormorehours(10hoursrepresents
0.5%ofthehoursinamonth)

.

54

WebelievethereshouldbeasinglequarterlyreportforR1andR2.TheR1portionwould
beverysimilartotoday,toincludereportingofevents>MSSC(butnotpartofcompliance
evaluation).ThequarterlyR2portionofthereportshouldhavethenumberofhoursthe
BAhadreserves<MSSCandanidentifierwhichhourswereexcludableunder2.1through
2.6.

Don’tChangefromPresentQuarterlyReporting:Wehavefundamentalconcernswith
changingthecurrentquarterlyreportingtoexceptionreporting.Wecanfindnodirective
forthischangewhichincreasescomplianceexposureandwillhaveunintended
consequencesinhowReserveSharingGroups(RSG)willoperate.Afailureofa
contingencyresourcetostartorstartaminutelatecancauseperformancethathasavery
lowscoreforthatsingleevent,eventhoughrecoveryisonlyaminutelateortwolate.
ThereareRSGsthatmitigatethiscomplianceriskbydeployingreservesformuchsmaller
events,whichhelpsreliabilitybyquicklyrecoveringfromsmallereventsandreplenishing
thesereservesaswellasgivingoperatorsrepeatedpracticeinreservedeployment.Since
eachandeveryeventisindividuallysanctionable,theseRSGswillquicklychangetheir
rulestoraisetheirreportablethresholdtotheinterconnectionminimum.Exception
reportingwillalsoeliminateadatasourcethatisusedforNERC’sRAPAgroupandthe
StateofReliabilityReport:http://www.nerc.com/pa/RAPA/ri/Pages/DCSEvents.aspx,
whichisanotherstepbackward.

onthereportingofevents.TheSDTwouldwelcomeanyinformationthatyoucould
providetojustifythesuggestedmodification.

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Organization

55

354.First,theCommissiondirectstheEROtodevelopamodificationtothe
ReliabilityStandardrequiringthatanysinglereportabledisturbancethathasa
recoverytimeof15minutesorlongerbereportedasaviolationoftheDisturbance
ControlStandard.ThisisconsistentwithourpositionintheNOPRandNERC’s

FromOrder693

Theindividualeventreportingmovesthecomplianceprocesstomeetthealreadyused
enforcementprocess.ThisalsosatisfiesaFERCOrder693directive.

Ifweassumethatthetotalresponseprovidedinthequarterdividedbythetotalresponse
requiredinthequarter,onlytheMWsfailedtobedeliveredmatters,nottheamountof
timeafterwards.Therefore,anindividualeventevaluationprovidesforamuchbetter
meanstodeterminetheimpacttoreliabilityfromasinglefailureasopposedtoaquarterly
mishmashofallevents.Thedraftingteambelievesthatwhileaquarterlyreportmay
providegooddatafortrendanalysis,itisapoormeanstodeterminecompliance.

1. Theminimumrequirementforcomplianceis100percentsoanyfailuretorespond
causesanonͲcompliance.Thequestionthenishowisafinedetermined?Shoulditbe
basedonthepercentageofeventsforwhichcompliancewas/wasnotobtained,the
percentageoffailedresponse(i.e.totalresponseneededforalleventswas1,000,
responsereceivedwas950)
2. Quarterlyreportingaveragescanmovebasedonthenumberofreportableeventsina
quarter,thesizeofreportableeventsorothervariablethatarguablehavenobearing
ontheimpacttotheBESofanentity’sfailuretomeettheresponserequirement.
Dependingontheanswertothefirstissue,thismayormaynotbeareasonable
metric.Justbecauseithasbeenusedforcompliancepurposes,thatdoesnotmeanit
isareasonablemeasureofreliabilityorimpacttoreliability.

Individualeventreportingversusquarterlyreportingincludesthefollowingpoints:

Thereportingapproachneednothardcodedinrequirements,butcouldbecompliance
sectionofthestandard.

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.

Organization



TheSDThasmadesignificantmodificationstoRequirementR1.

56

***(ii)aftermultipleBalancingContingencyEventsforwhichthecombined[capacity]
magnitudeexceedstheResponsibleEntity'sMostSevereSingleContingencyforthose
eventsthatoccurwithina105Ͳminuteperiod.***Contingenciesofpartiallyloaded
generatorsremovenotonlyMWfromtheBA,butthereservestheyhadasheadroom.It
ispossibletohavemultiplecontingencieswheretheMWlossis<MSSC,butreservesthat
werelostcompletelydepletetheBAofitscontingencyreserves.Thereshouldbe
clarificationthatthemagnitudelossisbasedoncapacity,notMWloss.

***1.2.AResponsibleEntityisnotsubjecttocompliancewithRequirementR1whenitis
experiencingaReliabilityCoordinatorapprovedEnergyEmergencyAlertLevelunder
whichContingencyReserveshavebeenactivated[ordepleted].***Contingenciescan
happenthattakeawayreserveswithoutthereservesbeingactivated.Andifthese
contingenciesaren’t“sudden”,thenitappearsthereisnoacknowledgmentofthereserve
lossunderthestandard.

WealsohadcommentsonafewspecificitemsinR1.Oursuggestedwordingchangesare
in[].

positioninresponsetotheStaffPreliminaryAssessmentoftheRequirementsin
BALͲ002Ͳ0,andwasnotdisputedorcommenteduponbyanyNOPRcommenters

Question1Comment

ConsiderationofComments:Project2010Ͳ14.1Phase1ofBalancingAuthorityReliabilityͲbasedControls–BALͲ002Ͳ2
Posted:July2015.



ENDOFREPORT

Organization

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

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
(Describe the type of action associated with this posting, such as 30-day informal comment
period, 45-day formal comment period with parallel ballot, 45-day formal comment period with
parallel additional ballot, final ballot.)

Completed Actions

Date

The SAR for Project 2007-18, Reliability Based Controls, was posted
for a 30-day formal industry comment period.

May 15, 2007

A revised SAR for Project 2007-05, Reliability Based Controls, was
posted for a second 30-day formal industry comment period.

September 10, 2007

The Standards Committee approved Project 2007-18, Reliability
Based Controls, to be moved to standard drafting.

December 11, 2007

The SAR for Project 2007-05, Balancing Authority Controls, was
posted for a 30-day formal industry comment period.

July 3, 2007

The Standards Committee approved Project 2007-05, Balancing
Authority Controls, to be moved to standard drafting.

January 18, 2008

The Standards Committee approved the merger of Project 2007-05,
Balancing Authority Controls, and Project 2007-18, Reliability-based
Control, as Project 2010-14, Balancing Authority Reliability-based
Controls.

July 28, 2010

The NERC Standards Committee approved breaking Project 2010-14,
Balancing Authority Reliability-based Controls, into two phases and
moving Phase 1 (Project 2010-14.1, Balancing Authority Reliabilitybased Controls – Reserves) into formal standards development.

July 13, 2011

The draft standard was posted for 30-day formal industry comment
period.

June 4, 2012

The draft standard was posted for 45-day formal industry comment
period and initial ballot.

March 12, 2013

The third draft standard was posted for 45-day formal industry
comment period and additional ballot.

August 2, 2013

Posting #7 of Standard BAL-002-2: July 2015

Page 1 of 15

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

The fourth draft standard was posted for 45-day formal industry
comment period and additional ballot.

October 28, 2013

The fifth draft standard was posted for a 45 day formal industry
comment period and additional ballot.

August 20, 2014

The sixth draft standard was posted for a 45-day formal industry
comment period and additional ballot.

January 29, 2015

Anticipated Actions

Date

45-day formal comment period with parallel additional ballot

June/July 2015

Final ballot

July 2015

NERC Board adoption

August 2015

Posting #7 of Standard BAL-002-2: July 2015

Page 2 of 15

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

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:
Balancing Contingency Event: Any single event described in Subsections (A), (B), or (C) below,
or any series of such otherwise single events, with each separated from the next by one minute
or less.
A. Sudden loss of generation:
a. Due to
i. unit tripping,
ii. loss of generator Facility resulting in isolation of the generator from the
Bulk Electric System or from the responsible entity’s System, or
iii. sudden unplanned outage of transmission Facility;
b. And, that causes an unexpected change to the responsible entity’s ACE;
B. Sudden loss of an import, due to unplanned outage of transmission equipment that
causes an unexpected imbalance between generation and Demand on the
Interconnection.
C. Sudden restoration of a Demand that was used as a resource that causes an unexpected
change to the responsible entity’s ACE.
Most Severe Single Contingency (MSSC): The Balancing Contingency Event, due to a single
contingency as identified and maintained in the system models within the Reserve Sharing
Group (RSG) or a Balancing Authority’s area that is not part of a Reserve Sharing Group, that
would result in the greatest loss (measured in MW) of resource output used by the RSG or a
Balancing Authority that is not participating as a member of a RSG at the time of the event to
meet Firm Demand and export obligation (excluding export obligation for which Contingency
Reserve obligations are being met by the Sink Balancing Authority).
Reportable Balancing Contingency Event: Any Balancing Contingency Event occurring within a
one-minute interval of an initial sudden decline in ACE based on EMS scan rate data that results
in a loss of MW output less than or equal to the Most Severe Single Contingency, and greater
than or equal to the lesser amount of: (i) 80% of the Most Severe Single Contingency, or (ii) the
amount listed below for the applicable Interconnection. Prior to any given calendar quarter,
the 80% threshold may be reduced by the responsible entity upon written notification to the
Regional Entity.
x

Eastern Interconnection - 900 MW

x

Western Interconnection – 500 MW

Posting #7 of Standard BAL-002-2: July 2015

Page 3 of 15

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

x

ERCOT – 800 MW

x

Quebec – 500 MW

Contingency Event Recovery Period: A period that begins at the time that the resource output
begins to decline within the first one-minute interval of a Reportable Balancing Contingency
Event, and extends for fifteen minutes thereafter.
Contingency Reserve Restoration Period: A period not exceeding 90 minutes following the end
of the Contingency Event Recovery Period.
Pre-Reporting Contingency Event ACE Value: The average value of Reporting ACE, or Reserve
Sharing Group Reporting ACE when applicable, in the 16-second interval immediately prior to
the start of the Contingency Event Recovery Period based on EMS scan rate data.
Reserve Sharing Group Reporting ACE: At any given time of measurement for the applicable
Reserve Sharing Group (RSG), the algebraic sum of the ACEs (or equivalent as calculated at such
time of measurement) of the Balancing Authorities participating in the RSG at the time of
measurement.
Rationale for Contingency Reserve Definition: Originally a waiver of the R3
Contingency Reserve Restoration requirement was proposed in the event of an
Energy Emergency Alert (EEA). This was predicated on a definition of Contingency
Reserve that did not include readiness to reduce Firm Demand during the
Contingency Reserve Restoration Period during an EEA and on concern that the
attempt to restore Contingency Reserve during an EEA could well result in actual
curtailment of Firm Demand in order to free up generation not to be used but merely
to be counted as restored Contingency Reserve when no other Balancing Contingency
Event arose. As an alternative to waiving R3, and to remedy the concern, readiness to
reduce Firm Demand during the Contingency Reserve Restoration Period during an
EEA was proposed for inclusion in the definition of Contingency Reserve as it would
make Firm Demand merely ready to be curtailed in case another Contingency arose
during an EEA.
Readiness to reduce Firm Demand here is a way of providing Contingency Reserves
exclusively when the Responsible Entity is in a Contingency Reserve Restoration
Period during an emergency. Readiness means the RE is prepared to reduce Firm
Demand to mitigate events which may increase demand or reduce supply causing
unacceptable risk. The RE should have processes and procedures for direct control

Posting #7 of Standard BAL-002-2: July 2015

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BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

over the Firm Demand in place for it to be considered Contingency Reserves prior to
the event.
Contingency Reserve: The provision of capacity that may be deployed by the Balancing
Authority to respond to a Balancing Contingency Event and other contingency requirements
(such as Energy Emergency Alerts as specified in the associated EOP standard). A Balancing
Authority may include in its restoration of Contingency Reserve readiness to reduce Firm
Demand and include it if, and only if, the Balancing Authority:
x

is experiencing a Reliability Coordinator declared Energy Emergency Alert level, and

x

is utilizing its Contingency Reserve to mitigate an operating emergency in
accordance with its emergency Operating Plan.

Posting #7 of Standard BAL-002-2: July 2015

Page 5 of 15

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

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: Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event

2.
3.

Number: BAL-002-2
Purpose: To ensure the Balancing Authority or Reserve Sharing Group balances
resources and demand and returns the Balancing Authority's or Reserve Sharing
Group's Area Control Error to defined values (subject to applicable limits) following a
Reportable Balancing Contingency Event.

4.

Applicability:
4.1. Responsible Entity
4.1.1. Balancing Authority
4.1.1.1.
A Balancing Authority that is a member of a Reserve
Sharing Group is the Responsible Entity only in periods during
which the Balancing Authority is not in active status under the
applicable agreement or governing rules for the Reserve Sharing
Group.
4.1.2. Reserve Sharing Group

5.

Effective Date: See the Implementation Plan for BAL-002-2.

6.

Background:
Reliably balancing an Interconnection requires frequency management and all of its
aspects. Inputs to frequency management include Tie-Line Bias Control, Area Control
Error (ACE), and the various Requirements in NERC Resource and Demand Balancing
Standards, specifically BAL-001-2 Real Power Balancing Control Performance and BAL003-1 Frequency Response and Frequency Bias Setting.

B. Requirements and Measures

Posting #7 of Standard BAL-002-2: July 2015

Page 6 of 15

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

Rationale for Requirement R1: Requirement R1 reflects the operating principles first
established by NERC Policy 1 (Generation Control and Performance). Its objective is to
assure the Responsible Entity balances resources and demand and returns its Reporting
Area Control Error (ACE) to defined values (subject to applicable limits) following a
Reportable Balancing Contingency Event. It requires the Responsible Entity to recover
from events that would be less than or equal to the Responsible Entity’s MSSC. It
establishes the amount of Contingency Reserve and recovery and restoration timeframes
the Responsible Entity must demonstrate in a compliance evaluation. It is intended to
eliminate the ambiguities and questions associated with the existing standard. In
addition, it allows Responsible Entities to have a clear way to demonstrate compliance
and support the Interconnection to the full extent of its MSSC.
Requirement R1 does not apply when an entity experiences a Balancing Contingency
Event that exceeds its MSSC (which includes multiple Balancing Contingency Events as
described in R1 part 1.3.2 below) because a fundamental goal of the SDT is to assure the
Responsible Entity has enough flexibility to maintain service to Demand while managing
reliability. The SDT’s intent is to eliminate any potential overlap or conflict with any other
NERC Reliability Standard to eliminate duplicative reporting, and other issues.
Commenters suggested a Quarterly Compliance similar to the current reports sent to
NERC. The drafting team attempted to draft measurement language and VSL’s for
quarterly monitoring of compliance to R1. But the drafting team found that the VSL levels
developed were likely to place smaller BA’s and RSGs in a severe violation regardless of
the size of the failure. Therefore, the drafting team has not adopted a quarterly
compliance calculation. Also, the proposed requirement and compliance process meets
the directive in Paragraph 354 of Order 693.
Finally, commenters have suggested that the language in R1 part 1.3 be changed to
specifically state under which EEA level the exclusion applies. The drafting team disagrees
with this proposal. NERC is in the process of changing the EEA levels and what is expected
in each level. The current EEA levels suggest that when an entity is experiencing an EEA
Level 2 or 3 it is short of Contingency Reserves as normally defined to exclude readiness
to curtail a specific amount of Firm Demand. Under the proposed EEA process, this would
only be during an EEA Level 3. In order to reduce the need for consequent modifications
of the BAL-002 standard, the drafting team has developed the proposed language.
R1.

The Responsible Entity experiencing a Reportable Balancing Contingency Event shall:
[Violation Risk Factor: Medium] [Time Horizon: Real-time Operations]
1.1. within the Contingency Event Recovery Period, demonstrate recovery by
returning its Reporting ACE to at least the recovery value of:

Posting #7 of Standard BAL-002-2: July 2015

Page 7 of 15

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

x

zero (if its Pre-Reporting Contingency Event ACE Value was positive or equal
to zero); however, any Balancing Contingency Event that occurs during the
Contingency Event Recovery Period shall reduce the required recovery: (i)
beginning at the time of, and (ii) by the magnitude of, such individual
Balancing Contingency Event,

or,
x

its Pre-Reporting Contingency Event ACE Value (if its Pre-Reporting
Contingency Event ACE Value was negative); however, any Balancing
Contingency Event that occurs during the Contingency Event Recovery Period
shall reduce the required recovery: (i) beginning at the time of, and (ii) by the
magnitude of, such individual Balancing Contingency Event.

1.2. document all Reportable Balancing Contingency Events using CR Form 1.
1.3. deploy Contingency Reserve, within system constraints, to respond to all
Reportable Balancing Contingency Events, however, it is not subject to
compliance with Requirement R1 part 1.1 if:
1.3.1 the Responsible Entity is:
x

experiencing a Reliability Coordinator declared Energy Emergency
Alert Level, and

x

utilizing its Contingency Reserve to mitigate an operating emergency in
accordance with its emergency Operating Plan, and

x

the Responsible Entity has depleted its Contingency Reserve to a level
below its Most Severe Single Contingency

or,
1.3.2 the Responsible Entity experiences:
x

multiple Contingencies where the combined MW loss exceeds its
Most Severe Single Contingency and that are defined as a single
Balancing Contingency Event, or

x

multiple Balancing Contingency Events within the sum of the time
periods defined by the Contingency Event Recovery Period and
Contingency Reserve Restoration Period whose combined magnitude
exceeds the Responsible Entity's Most Severe Single Contingency.

M1. Each Responsible Entity shall have, and provide upon request, as evidence, a CR Form
1 with date and time of occurrence to show compliance with Requirement R1. If
Requirement R1 part 1.3 applies, then dated documentation that demonstrates
compliance with Requirement R1 part 1.3 must also be provided.

Posting #7 of Standard BAL-002-2: July 2015

Page 8 of 15

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

Rationale for Requirement R2: R2 establishes the need to actively plan in the near term
(e.g., day-ahead) for expected Reportable Balancing Contingency Events. This
requirement is similar to the current standard which requires an entity to have available a
level of contingency reserves equal to or greater than its Most Severe Single Contingency.
R2.

Each Responsible Entity shall develop, review and maintain annually, and implement
an Operating Process as part of its Operating Plan to determine its Most Severe
Single Contingency and to have Contingency Reserve equal to, or greater than the
Responsible Entity’s Most Severe Single Contingency available for maintaining
system reliability. [Violation Risk Factor: Medium] [Time Horizon: Operations
Planning]

M2. Each Responsible Entity will have the following documentation to show compliance
with Requirement R2:
x

a dated Operating Process;

x

evidence to indicate that the Operating Process has been reviewed and
maintained annually; and,

x

evidence such as Operating Plans or other operator documentation that
demonstrate that the entity determines its Most Severe Single Contingency
and that Contingency Reserves equal to or greater than its Most Severe Single
Contingency are included in this process.

Rationale for Requirement R3: This requirement is similar to the existing requirement
that an entity that has experienced an event shall restore its Contingency Reserves within
105 minutes of the event. Note that if an entity is experiencing an EEA it may need to
depend on potential availability (or make ready for potential curtailment) of its firm loads
to restore Contingency Reserve. This is the reason for the changes to the definition of
Contingency Reserve in the posting.
R3.

Each Responsible Entity, following a Reportable Balancing Contingency Event, shall
restore its Contingency Reserve to at least its Most Severe Single Contingency,
before the end of the Contingency Reserve Restoration Period, but any Balancing
Contingency Event that occurs before the end of a Contingency Reserve Restoration
period resets the beginning of the Contingency Event Recovery Period. [Violation
Risk Factor: Medium] [Time Horizon: Real-time Operations]

Posting #7 of Standard BAL-002-2: July 2015

Page 9 of 15

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

M3. Each Responsible Entity will have documentation demonstrating its Contingency
Reserve was restored within the Contingency Reserve Restoration Period, such as
historical data, computer logs or operator logs.
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 Responsible Entity shall retain data or evidence to show compliance for
the current year, plus three previous calendar years, unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer
period of time as part of an investigation.
If a Responsible Entity is found noncompliant, it shall keep information related
to the noncompliance until found compliant, or for the time period specified
above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and
all subsequent requested and submitted records.
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
The Responsible Entity may use Contingency Reserve for any Balancing
Contingency Event and as required for any other applicable standards.

Posting #7 of Standard BAL-002-2: July 2015

Page 10 of 15

Real-time
Operations

Operations
Planning

R1.

R2.

Lower VSL

Medium The Responsible Entity
developed and
implemented an
Operating Process to
determine its Most
Severe Single
Contingency and to
have Contingency
Reserve equal to, or

The Responsible Entity
failed to use CR Form 1
to document a
Reportable Balancing
Contingency Event.

OR

Medium The Responsible Entity
achieved less than
100% but at least 90%
of required recovery
from a Reportable
Balancing Contingency
Event during the
Contingency Event
Recovery Period

VRF

Draft #7 of Standard BAL-002-2: July 2015

Time
Horizon

R#

Table of Compliance Elements

N/A

The Responsible Entity
achieved less than
90% but at least 80%
of required recovery
from a Reportable
Balancing Contingency
Event during the
Contingency Event
Recovery Period.

Moderate VSL

The Responsible Entity
developed an
Operating Process to
determine its Most
Severe Single
Contingency and to
have Contingency
Reserve equal to, or
greater than the

The Responsible Entity
achieved less than
80% but at least 70%
of required recovery
from a Reportable
Balancing Contingency
Event during the
Contingency Event
Recovery Period.

High VSL

Violation Severity Levels

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event

Page 11 of 15

The Responsible Entity
failed to develop an
Operating Process to
determine its Most
Severe Single
Contingency and to
have Contingency
Reserve equal to, or
greater than the

The Responsible Entity
achieved less than
70% of required
recovery from a
Reportable Balancing
Contingency Event
during the
Contingency Event
Recovery Period.

Severe VSL

Real-time
Operations

Medium The Responsible Entity
restored less than
100% but at least 90%
of required
Contingency Reserve
following a Reportable
Balancing Contingency
Event during the
Contingency Event
Restoration Period.

The Responsible Entity
restored less than 90%
but at least 80% of
required Contingency
Reserve following a
Reportable Balancing
Contingency Event
during the
Contingency Event
Restoration Period.

The Responsible Entity
restored less than 80%
but at least 70% of
required Contingency
Reserve following a
Reportable Balancing
Contingency Event
during the
Contingency Event
Restoration Period.

Responsible Entity’s
Most Severe Single
Contingency but failed
to implement the
Operating Process.

Draft #7 of Standard BAL-002-2: July 2015

Version History

CR Form 1

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event Background Document

F. Associated Documents

None.

E. Interpretations

None.

D. Regional Variances

R3

greater than the
Responsible Entity’s
Most Severe Single
Contingency but failed
to maintain the
Operating Process.

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event

Page 12 of 15

The Responsible Entity
restored less than 70%
of required
Contingency Reserve
following a Reportable
Balancing Contingency
Event during the
Contingency Event
Restoration Period.

Responsible Entity’s
Most Severe Single
Contingency..

August 8, 2005

February 14,
2006

0

0
NERC BOT Adoption

Revised graph on page 3, “10 min.” to “Recovery
time.” Removed fourth bullet.

Removed “Proposed” from Effective Date

Effective Date

Action

Complete revision

Errata

Errata

New

Change Tracking

Draft #7 of Standard BAL-002-2: July 2015

Page 13 of 15

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.

2

April 1, 2005

Date

0

Version

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event

Supplemental Material
[Application Guidelines, Guidelines and Technical Basis, Training Material,
Reference Material and/or other Supplemental Material]

Draft #7 of Standard BAL-002-2: July 2015

Page 14 of 15

Supplemental Material
Rationale
Upon Board approval, the text from the rationale boxes will be moved to this section.

Draft #7 of Standard BAL-002-2: July 2015

Page 15 of 15

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

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
(Describe the type of action associated with this posting, such as 30-day informal comment
period, 45-day formal comment period with parallel ballot, 45-day formal comment period with
parallel additional ballot, final ballot.)

Completed Actions

Date

The SAR for Project 2007-18, Reliability Based Controls, was posted
for a 30-day formal industry comment period.

May 15, 2007

A revised SAR for Project 2007-05, Reliability Based Controls, was
posted for a second 30-day formal industry comment period.

September 10, 2007

The Standards Committee approved Project 2007-18, Reliability
Based Controls, to be moved to standard drafting.

December 11, 2007

The SAR for Project 2007-05, Balancing Authority Controls, was
posted for a 30-day formal industry comment period.

July 3, 2007

The Standards Committee approved Project 2007-05, Balancing
Authority Controls, to be moved to standard drafting.

January 18, 2008

The Standards Committee approved the merger of Project 2007-05,
Balancing Authority Controls, and Project 2007-18, Reliability-based
Control, as Project 2010-14, Balancing Authority Reliability-based
Controls.

July 28, 2010

The NERC Standards Committee approved breaking Project 2010-14,
Balancing Authority Reliability-based Controls, into two phases and
moving Phase 1 (Project 2010-14.1, Balancing Authority Reliabilitybased Controls – Reserves) into formal standards development.

July 13, 2011

The draft standard was posted for 30-day formal industry comment
period.

June 4, 2012

The draft standard was posted for 45-day formal industry comment
period and initial ballot.

March 12, 2013

The third draft standard was posted for 45-day formal industry
comment period and additional ballot.

August 2, 2013

Posting #76 of Standard BAL-002-2: July: January, 2015

Page 1 of 19

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

The fourth draft standard was posted for 45-day formal industry
comment period and additional ballot.

October 28, 2013

The fifth draft standard was posted for a 45 day formal industry
comment period and additional ballot.

August 20, 2014

The sixth draft standard was posted for a 45-day formal industry
comment period and additional ballot.

January 29, 2015

Anticipated Actions

Date

45-day formal comment period with parallel additional ballot

July 2015

Final ballot

October 2015

NERC Board adoption

November 2015

Posting #76 of Standard BAL-002-2: July: January, 2015

Page 2 of 19

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

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:
Balancing Contingency Event: Any single event described in Subsections (A), (B), or (C) below,
or any series of such otherwise single events, with each separated from the next by less than
one minute or less.
A. Sudden loss of generation:
a. Due to
i. unitUnit tripping,
ii. lossLoss of generator Facility resulting in isolation of the generator from
the Bulk Electric System or from the responsible entity’s Systemelectric
system, or
iii. suddenSudden unplanned outage of transmission Facility;
b. And, that causes an unexpected change to the responsible entity’s ACE;
B. Sudden loss of an import, due to unplannedforced outage of transmission equipment
that causes an unexpected imbalance between generation and Demandload on the
Interconnection.
C. Sudden restoration of a Demandload that was used as a resource that causes an
unexpected change to the responsible entity’s ACE.
Most Severe Single Contingency (MSSC): The Balancing Contingency Event, due to a single
contingency as identified and maintained in the system models within the Reserve Sharing
Group (RSG) or a Balancing Authority’s area that is not part of a Reserve Sharing Group, that
would result in the greatest loss (measured in MW) of resource output used by the Reserve
Sharing Group (RSG) or a Balancing Authority that is not participating as a member of a RSG at
the time of the event to meet Firm Demandfirm system load and export obligation (excluding
export obligation for which Contingency Reserve obligations are being met by the Sink
Balancing Authority).
Reportable Balancing Contingency Event: Any Balancing Contingency Event occurring within a
one-minute interval of an initial sudden decline in ACE based on EMS scan rate data that
resultsresulting in a loss of MW output less than or equal to the Most Severe Single
Contingency, and greater than or equal to the lesser amount of: (i) 80% of the Most Severe
Single Contingency, or (ii) the amount listed below for the applicable Interconnection., and
occurring within a one-minute interval of the initial sudden decline in ACE based on EMS scan

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BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

rate data. Prior to any given calendar quarter, the 80% threshold may be reduced by the
responsible entity upon written notification to the Regional Entity.
x

Eastern Interconnection - 900 MW

x

Western Interconnection – 500 MW

x

ERCOT – 800 MW

x

Quebec – 500 MW

Contingency Event Recovery Period: A period that beginsbeginning at the time that the
resource output begins to decline within the first one-minute interval ofthat defines a
Reportable Balancing Contingency Event, and extends for fifteen minutes thereafter.
Contingency Reserve Restoration Period: A period not exceeding 90 minutes following the end
of the Contingency Event Recovery Period.
Pre-Reporting Contingency Event ACE Value: The average value of Reporting ACE, or Reserve
Sharing Group Reporting ACE when applicable, in the 16-second interval immediately prior to
the start of the Contingency Event Recovery Period based on EMS scan rate data.
Reserve Sharing Group Reporting ACE: At any given time of measurement for the applicable
Reserve Sharing Group (RSG),, the algebraic sum of the ACEs (or equivalent as calculated at
such time of measurement) of the Balancing Authorities participating in the RSGReserve
Sharing Group at the time of measurement.
Rationale for Contingency Reserve Definition: Originally a waiver of the R3
Contingency Reserve Restoration requirement was proposed in the event of an
Energy Emergency Alert (EEA). This was predicated on a definition of Contingency
Reserve that did not include readiness to reduce Firm Demand during the
Contingency Reserve Restoration Period during an EEA and on concern that the
attempt to restore Contingency Reserve during an EEA could well result in actual
curtailment of Firm Demand in order to free up generation not to be used but merely
to be counted as restored Contingency Reserve when no other Balancing Contingency
Event arose. As an alternative to waiving R3, and to remedy the concern, readiness to
reduce Firm Demand during the Contingency Reserve Restoration Period during an
EEA was proposed for inclusion in the definition of Contingency Reserve as it would
make Firm Demand merely ready to be curtailed in case another Contingency arose
during an EEA.

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BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
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Readiness to reduce Firm Demand here is a way of providing Contingency Reserves
exclusively when the Responsible Entity is in a Contingency Reserve Restoration
Period during an emergency. Readiness means the RE is prepared to reduce Firm
Demand to mitigate events which may increase demand or reduce supply causing
unacceptable risk. The RE should have processes and procedures for direct control
over the Firm Demand in place for it to be considered Contingency Reserves prior to
the event.
Contingency Reserve: The provision of capacity that may be deployed by the Balancing
Authority to respond to a Balancing Contingency Event and other contingency requirements
(such as Energy Emergency Alerts as specified in the associated EOP standard). A Balancing
Authority may include in its restoration of Contingency Reserve readiness to reduce Firm
Demand and include it if, and only if, the Balancing Authority:
x

is experiencing a Reliability Coordinator declared Energy Emergency Alert level, and

x

is utilizing its Contingency Reserve to mitigate an operating emergency in
accordance with its emergency Operating PlanThe capacity may be provided by
resources such as Demand-Side Management (DSM), Interruptible Load and
unloaded generation.

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BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

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: Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event

2.
3.

Number: BAL-002-2
Purpose: To ensure the Balancing Authority or Reserve Sharing Group balances
resources and demand and returns the Balancing Authority's or Reserve Sharing
Group's Area Control Error to defined values (subject to applicable limits) following a
Reportable Balancing Contingency Event.

4.

Applicability:
4.1. Responsible Entity
4.1.1. Balancing Authority
4.1.1.1.
A Balancing Authority that is a member of a Reserve
Sharing Group is the Responsible Entity only in periods during
which the Balancing Authority is not in active status under the
applicable agreement or governing rules for the Reserve Sharing
Group.
4.1.2. Reserve Sharing Group

5.

Effective Date: See the Implementation Plan for BAL-002-2. Effective Date: The
standard shall become effective on the first day of the first calendar quarter that is six
months after the date that the standard is approved by an applicable governmental
authority or as otherwise provided for in a jurisdiction where approval by an
applicable governmental authority is required for a standard to go into effect. Where
approval by an applicable governmental authority is not required, the standard shall
become effective on the first day of the first calendar quarter that is six months after
the date the standard is adopted by the NERC Board of Trustees or as otherwise
provided for in that jurisdiction.

6.

Background:
Reliably balancing an Interconnection requires frequency management and all of its
aspects. Inputs to frequency management include Tie-Line Bias Control, Area Control
Error (ACE), and the various Requirements in NERC Resource and Demand Balancing
Standards, specifically BAL-001-2 Real Power Balancing Control Performance and BAL003-1 Frequency Response and Frequency Bias Setting.

B. Requirements and Measures

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BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

Rationale for Requirement R1: Requirement R1 reflects the operating principles first
established by NERC Policy 1 (Generation Control and Performance).. Its objective is to
assure the Responsible Entity balances resources and demand and returns its
ReportingReportable Area Control Error (ACE) to defined values (subject to applicable
limits) following a Reportable Balancing Contingency Event. It requires the Responsible
Entity to recover from events that would be less than or equal to the Responsible Entity’s
MSSC. It establishes the amount of Contingency Reserve and recovery and restoration
timeframes the Responsible Entity must demonstrate in a compliance evaluation. It is
intended to eliminate the ambiguities and questions associated with the existing
standard. In addition, it allows Responsible Entities to have a clear way to demonstrate
compliance and support the Interconnection to the full extent of its MSSC.
Requirement R1 does not apply when an entity experiences a Balancing Contingency
Event that exceeds its MSSC (which includes multiple Balancing Contingency Events as
described in R1 part 1.3.2 below) because a fundamental goal of the SDT is to assure the
Responsible Entity has enough flexibility to maintain service to Demandload while
managing reliability. TheAlso, the SDT’s intent is to eliminate any potential overlap or
conflict with any other NERC Reliability Standard to eliminate duplicative reporting, and
other issues.
Commenters suggested a Quarterly Compliance similar to the current reports sent to
NERC. The drafting team attempted to draft measurement language and VSL’s for
quarterly monitoring of compliance to R1. But the drafting team found that the VSL levels
developed were likely to place smaller BA’s and RSGs in a severe violation regardless of
the size of the failure. Therefore, the drafting team has not adopted a quarterly
compliance calculation. Also, the proposed requirement and compliance process meets
the directive in Paragraph 354 of Order 693.
Finally, commenters have suggested that the language in R1 part 1.3 be changed to
specifically state under which EEA level the exclusion applies. The drafting team disagrees
with this proposal. NERC is in the process of changing the EEA levels and what is expected
in each level. The current EEA levels suggest that when an entity is experiencing an EEA
Level 2 or 3 it is short of Contingency Reserves as normally defined to exclude readiness
to curtail a specific amount of Firm Demand. Under the proposed EEA process, this would
only be during an EEA Level 3. In order to reduce the need for consequent modifications
of the BAL-002 standard, the drafting team has developed the proposed language.
R1.

The Responsible Entity experiencing a Reportable Balancing Contingency Event shall,
within the Contingency Event Recovery Period, demonstrate recovery by returning its
Reporting ACE to at least the recovery value of: [Violation Risk Factor: Medium] [Time
Horizon: Real-time Operations]
x

Zero, (if its Pre-Reporting Contingency Event ACE Value was positive or equal
to zero); however, during the Contingency Event Recovery Period, any
Balancing Contingency Event that occurs shall reduce the required recovery: (i)

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BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

beginning at the time of, and (ii) by the magnitude of, each individual
Balancing Contingency Event,
or,
Its Pre-Reporting Contingency Event ACE Value, (if its Pre-Reporting Contingency
Event ACE Value was negative); however, during the Contingency Event Recovery
Period, any Balancing Contingency Event that occurs shall reduce the required
recovery: (i) beginning at the time of, and (ii) by the magnitude of, each individual
Balancing Contingency Event.
1.1. within the Contingency Event Recovery Period, demonstrate recovery by
returning its Reporting ACE to at least the recovery value of:
x

zero (if its Pre-Reporting Contingency Event ACE Value was positive or equal
to zero); however, any Balancing Contingency Event that occurs during the
Contingency Event Recovery Period shall reduce the required recovery: (i)
beginning at the time of, and (ii) by the magnitude of, such individual
Balancing Contingency Event,

or,
x

its Pre-Reporting Contingency Event ACE Value (if its Pre-Reporting
Contingency Event ACE Value was negative); however, any Balancing
Contingency Event that occurs during the Contingency Event Recovery Period
shall reduce the required recovery: (i) beginning at the time of, and (ii) by the
magnitude of, such individual Balancing Contingency Event.

1.1.1.2.
document allAll Reportable Balancing Contingency Events will be
documented using CR Form 1.
1.2.1.3.
deploy Contingency Reserve, within system constraints, to respond to all
Reportable Balancing Contingency Events, however, it is A Responsible Entity is
not subject to compliance with Requirement R1 part 1.1 if:when it is
experiencing a Reliability Coordinator approved Energy Emergency Alert Level
under which Contingency Reserves have been activated.
x

the Responsible Entity is:
o experiencing a Reliability Coordinator declared Energy Emergency
Alert Level, and
o utilizing its Contingency Reserve to mitigate an operating emergency in
accordance with its emergency Operating Plan, and
o the Responsible Entity has depleted its Contingency Reserve to a level
below its Most Severe Single Contingency

or,
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BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

1.3.2 the Responsible Entity experiences:Requirement R1 (in its entirety) does
not apply:
x

multiple Contingencies where(i) when the combined MW loss
Responsible Entity experiences a Balancing Contingency Event that
exceeds its Most Severe Single Contingency and that are defined as a
single Balancing Contingency Event, or

x

(ii) after multiple Balancing Contingency Events within the sum of the
time periods defined by the Contingency Event Recovery Period and
Contingency Reserve Restoration Period whosefor which the
combined magnitude exceeds the Responsible Entity's Most Severe
Single Contingency for those events that occur within a 105-minute
period.

M1. Each Responsible Entity shall have, and provide upon request, as evidence, a CR Form
1 with date and time of occurrence to show compliance with Requirement R1. If
Requirement R1 part 1.3 applies, orthen dated documentation that demonstrates
compliance with Requirement R1 part1.2 and 1.3 must also be provided.
Rationale for Requirement R2: R2 establishes a uniform continent-wide contingency
reserve requirement. R2 establishes a requirement that contingency reserve be at least
equal to the need to actively plan in applicable entity’s Most Severe Single Contingency.
By including a definition of Most Severe Single Contingency and R2, a consistent uniform
continent-wide contingency reserve requirement has been established. Its goal is to
assure that the near term (e.g., day-ahead) for expectedResponsible Entity will have
sufficient contingency reserve that can be deployed to meet R1.
FERC Order 693 (at P356) directed BAL-002 to be developed as a continent-wide
contingency reserve policy. R2 fulfills the requirement associated with the required
amount of contingency reserve a Responsible Entity must have available to respond to a
Reportable Balancing Contingency Events. This requirement is similar to the current
standardEvent. Within FERC Order 693 (at P336) the Commission noted that the
appropriate mix of operating reserve, spinning reserve and non-spinning reserve should
be addressed. However, the Order predated the approval of the new BAL-003, which
requires an entity to have available a level of addresses frequency responsive reserve and
the amount of frequency response obligation. With the development of BAL-003, and the
associated reliability performance requirement, the SDT believes that, with R2 of BAL-002
and the approval of BAL-003, the Commission’s goals of a continent-wide contingency
reserves equal to policy is met. The suites of BAL standards (BAL-001, BAL-002, and BAL003) are all performance-based. With the suite of standards and the specific
requirements within each respective standard, a continent-wide contingency policy is
established.

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BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

In the Violation Severity Levels for Requirement R1, the impact of the Responsible Entity
recovering from a Reportable Balancing Contingency Event depends on the amount of its
Contingency Reserve available and whether it has sufficient response. Additionally, the
drafting team understands that the Responsible Entity’s available Contingency Reserve
may vary slightly from MSSC at any time. This variability is recognized in Requirement R2
through averaging the available Contingency Reserve over each Clock Hour.
The ideal goal of maintaining an amount of Contingency Reserve to cover the Most
Severe Single Contingency at all times is not necessarily in the best interest of reliability.
It may have the unintended result of tying operators' hands by removing use of their
available contingency reserve from their toolbox in order to maintain service to load or
greatermanage other reliability issues. By allowing for the occasional use of this minimal
amount of Contingency Reserve at the operators' discretion for other contingencies,
reliability is enhanced. The SDT crafted the proposed standard to encourage the
operators to use, at their discretion and within the limits set forth in the standard, their
available contingency reserve to best serve reliability in Real-time. The last thing that
anyone desires is to have Contingency Reserve held available and the lights go off
because the standard would penalize the operator for using the Contingency Reserve to
maintain service to the load. However, the drafting team did not believe that the use of
reserves for issues other than its Most Severe Single Contingency. a Reportable
Balancing Contingency Event should be unbounded. The SDT limited the use of
Contingency Reserve.
R2.

EachThe Responsible Entity shall develop, review and maintain annually, and
implement an Operating Process as part of Contingency Reserve, averaged over
each Clock Hour, greater than or equal to its Operating Plan to determine itsaverage
Clock Hour Most Severe Single Contingency and to have Contingency Reserve equal
to, or greater than , except during one or more of the following periods when the
Responsible Entity’s Most Severe Single Contingency available for maintaining
system reliability.Entity is: [Violation Risk Factor: Medium] [Time Horizon: Real-time
Operations Planning]
2.1 using its Contingency Reserve, for a period not to exceed 90 minutes,
to mitigate the reliability concerns associated with Contingencies that
are not Balancing Contingency Events; and/or
2.2 using its Contingency Reserve, for a period not to exceed 90 minutes,
to respond to an Operating Instruction requiring the use of
Contingency Reserve; and/or
2.3 using its Contingency Reserve for a period not to exceed 90 minutes,
to resolve the exceedance of a System Operating Limit (SOL) or
Interconnection Reliability Operation Limit (IROL) that requires the
use of Contingency Reserve; and/or
2.4 in a Contingency Reserve Restoration Period; and/or

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BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

2.5 in a Contingency Event Recovery Period; and/or
2.6 in an Energy Emergency Alert Level under which the Responsible
Entity no longer has required Contingency Reserve available provided
that the Responsible Entity has made preparations for interruption of
Firm Load to replace the shortfall of Contingency Reserve to avoid the
uncontrolled failure of components or cascading outages of the
Interconnection. For this exemption to apply, the preparations must
be initiated within 5 minutes from the time that the Energy
Emergency Alert Level is declared.
M2. Each Responsible Entity willshall have the following dated documentation to showthat
demonstrates compliance with Requirement R2:
M2.1

a dated Operating Process;

M2.2

evidence to indicate that the Operating Process has been reviewed. Evidence
of compliance may include, but is not limited to, documenting Contingencies
and maintained annually; and,

M2. evidence such as Operating Plans or otherEnergy Emergency Alert Levels through
outage records, operator documentation that demonstrate that the entity determines
its Most Severe Single Contingency and that Contingency Reserves equal to or greater
than its Most Severe Single Contingency are included in this process.logs, and others.
Compliance may be achieved by demonstrating that:
M2.1M2.3 Contingency Reserve, averaged over each Clock Hour, meets or exceeds
the required Contingency Reserve; or,
x

Contingency Reserve has been restored to the required Contingency Reserve
levels within the specified period: or,

x

the sum of the Contingency Reserve and Firm Load available as a substitute for
unavailable Contingency Reserve reaches the required Contingency Reserve
level within the specified period;
Any shortfall from compliance will be measured as compliance of 100% minus
the shortfall’s percentage share of MSSC.

If the recording of Contingency Reserve or MSSC is interrupted such that more than
50 percent of the samples within the clock hour are invalid data, then that clock hour
is excluded from evaluation. If any portion of the Clock Hour is excluded by rule in
Requirement R2, then compliance with that portion of the hour not excluded may be
shown by either determination of the integrated value for that portion of the hour
not excluded by the rule or an instantaneous value showing reserves any time during
the excluded period.

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BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

Rationale for Requirement R3: This requirement is similar to the existing requirement
that an entity that has experienced an event shall restore its Contingency Reserves within
105 minutes of the event. Note that if an entity is experiencing an EEA it may need to
depend on potential availability (or make ready for potential curtailment) of its firm loads
to restore Contingency Reserve. This is the reason for the changes to the definition of
Contingency Reserve in the posting.
R3.

Each Responsible Entity, following a Reportable Balancing Contingency Event, shall
restore its Contingency Reserve to at least its Most Severe Single Contingency,
before the end of the Contingency Reserve Restoration Period, but any Balancing
Contingency Event that occurs before the end of a Contingency Reserve Restoration
period resets the beginning of the Contingency Event Recovery Period. [Violation
Risk Factor: Medium] [Time Horizon: Real-time Operations]

M3. Each Responsible Entity will have documentation demonstrating its Contingency
Reserve was restored within the Contingency Reserve Restoration Period, such as
historical data, computer logs or operator logs.
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 Responsible Entity shall retain data or evidence to show compliance for
the current year, plus three previous calendar years, unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer
period of time as part of an investigation.
If a Responsible Entity is found noncompliant, it shall keep information related
to the noncompliance until found compliant, or for the time period specified
above, whichever is longer.

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BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

The Compliance Enforcement Authority shall keep the last audit records and
all subsequent requested and submitted records.
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
The Responsible Entity may use Contingency Reserve for any Balancing
Contingency Event and as required for any other applicable standards.

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Real-time
Operations

Real-time
Operations
Planning

R1.

R2.

Lower VSL

Medium The Responsible Entity
developed and
implemented an
Operating Process to
determine its Most
Severe Single
Contingency and to
havehad Contingency

The Responsible Entity
failed to use CR Form 1
to document a
Reportable Balancing
Contingency Event.

OR

Medium The Responsible Entity
achievedrecovered
less than 100% but at
leastmore than 90% of
required recovery
from a Reportable
Balancing Contingency
Event during the
Contingency Event
Recovery Period

VRF

Draft #7 of Standard BAL-002-2: July 2015: Date Submitted for Posting

Time
Horizon

R#

Table of Compliance Elements

N/AThe Responsible
Entity had Contingency
Reserve but the Clock
Hour average amount
of Contingency
Reserve was less than
90% of MSSC but was
greater than or equal

The Responsible Entity
achievedrecovered
90% or less than 90%
but at leastmore than
80% of required
recovery from a
Reportable Balancing
Contingency Event
during the
Contingency Event
Recovery Period.

Moderate VSL

The Responsible Entity
developed an
Operating Process to
determine its Most
Severe Single
Contingency and to
havehad Contingency
Reserve equal to, or

The Responsible Entity
achievedrecovered
80% or less than 80%
but at leastmore than
70% of required
recovery from a
Reportable Balancing
Contingency Event
during the
Contingency Event
Recovery Period.

High VSL

Violation Severity Levels

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event

Page 14 of 19

The Responsible Entity
failed to develop an
Operating Process to
determine its Most
Severe Single
Contingency and todid
not have Contingency
Reserve that was

The Responsible Entity
achievedrecovered
70% or less than 70%
of required recovery
from a Reportable
Balancing Contingency
Event during the
Contingency Event
Recovery Period.

Severe VSL

Real-time
Operations

Medium The Responsible Entity
restored less than
100% but at least 90%
of required
Contingency Reserve
following a Reportable
Balancing Contingency
Event during the
Contingency Event
Restoration Period.

Draft #7 of Standard BAL-002-2: July 2015: Date Submitted for Posting

None.

E. Interpretations

None.

D. Regional Variances

R3

Reserve equal to, or
but the Clock Hour
average amount of
Contingency Reserve
was less than 100% of
MSSC but was greater
than the Responsible
Entity’s Most Severe
Single Contingency but
failed to maintainor
equal to 90% of MSSC
as averaged over the
Operating
ProcessClock Hour.
The Responsible Entity
restored less than 90%
but at least 80% of
required Contingency
Reserve following a
Reportable Balancing
Contingency Event
during the
Contingency Event
Restoration Period.

to 80% of MSSC as
averaged over the
Clock Hour.

The Responsible Entity
restored less than 80%
but at least 70% of
required Contingency
Reserve following a
Reportable Balancing
Contingency Event
during the
Contingency Event
Restoration Period.

but the Clock Hour
average amount of
Contingency Reserve
was less than 80% of
MSSC but was greater
than the Responsible
Entity’s Most Severe
Single Contingency but
failed to implementor
equal to 70% of MSSC
as averaged over the
Operating
ProcessClock Hour.

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event

Page 15 of 19

The Responsible Entity
restored less than 70%
of required
Contingency Reserve
following a Reportable
Balancing Contingency
Event during the
Contingency Event
Restoration Period.

equal to, or greater
than 70% of MSSC
averaged over the
Responsible Entity’s
Most Severe Single
Contingency..Clock
Hour.

August 8, 2005

February 14,
2006

0

0

Action

NERC BOT Adoption

Revised graph on page 3, “10 min.” to “Recovery
time.” Removed fourth bullet.

Removed “Proposed” from Effective Date

Effective Date

Draft #7 of Standard BAL-002-2: July 2015: Date Submitted for Posting

Standards Attachments

2

April 1, 2005

Date

0

Version

Version History

CR Form 1

Complete revision

Errata

Errata

New

Change Tracking

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event Background Document

F. Associated Documents

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event

Page 16 of 19

Draft #7 of Standard BAL-002-2: July 2015: Date Submitted for Posting

Page 17 of 19

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.

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event

Supplemental Material
[Application Guidelines, Guidelines and Technical Basis, Training Material,
Reference Material and/or other Supplemental Material]

Draft #7 of Standard BAL-002-2: July 2015: Date Submitted for Posting

Page 18 of 19

Supplemental Material
Rationale
Upon Board approval, the text from the rationale boxes will be moved to this section.

Draft #7 of Standard BAL-002-2: July 2015: Date Submitted for Posting

Page 19 of 19

Implementation Plan

Project 2010-14.1 Balancing Authority Reliability-based Controls
- Reserves
Implementation Plan for BAL-002-2 – Disturbance Control Performance - Contingency Reserve for
Recovery from a Balancing Contingency Event
Approvals Required
BAL-002-2 – Disturbance Control Performance - Contingency Reserve for Recovery from a Balancing
Contingency Event
Prerequisite Approvals
None
Revisions to Glossary Terms
The following definitions shall become effective when BAL-002-2 becomes effective:
Balancing Contingency Event: Any single event described in Subsections (A), (B), or (C) below, or
any series of such otherwise single events, with each separated from the next by one minute or
less.
A. Sudden loss of generation:
a. Due to
i. unit tripping, or
ii. loss of generator Facility resulting in isolation of the generator from the Bulk
Electric System or from the responsible entity’s System, or
iii. sudden unplanned outage of transmission Facility;
b. And, that causes an unexpected change to the responsible entity’s ACE;
B. Sudden loss of an Import, due to forced outage of transmission equipment that causes an
unexpected imbalance between generation and Demand on the Interconnection.
C. Sudden restoration of a Demand that was used as a resource that causes an unexpected
change to the responsible entity’s ACE.
Most Severe Single Contingency (MSSC): The Balancing Contingency Event, due to a single
contingency as identified and maintained in the system models within the Reserve Sharing Group

(RSG) or a Balancing Authority’s area that is not part of a Res area that is not part of a Reserve
Sharing Group, that would result in the greatest loss (measured in MW) of resource output used by
the RSG or a Balancing Authority that is not participating as a member of a RSG at the time of the
event to meet Firm Demand and export obligation (excluding export obligation for which
Contingency Reserve obligations are being met by the Sink Balancing Authority).
Reportable Balancing Contingency Event: Any Balancing Contingency Event occurring within a
one-minute interval of an initial sudden decline in ACE based on EMS scan rate data that results in a
loss of MW output less than or equal to the Most Severe Single Contingency, and greater than or
equal to the lesser amount of: (i) 80% of the Most Severe Single Contingency, or (ii) the amount
listed below for the applicable Interconnection. Prior to any given calendar quarter, the 80%
threshold may be reduced by the responsible entity upon written notification to the Regional
Entity.
x

Eastern Interconnection – 900 MW

x

Western Interconnection – 500 MW

x

ERCOT – 800 MW

x

Quebec – 500 MW

Contingency Event Recovery Period: A period that begins at the time that the resource output
begins to decline within the first one-minute interval of a Reportable Balancing Contingency Event,
and extends for fifteen minutes thereafter.
Contingency Reserve Restoration Period: A period not exceeding 90 minutes following the end of
the Contingency Event Recovery Period.
Pre-Reporting Contingency Event ACE Value: The average value of Reporting ACE, or Reserve
Sharing Group Reporting ACE when applicable, in the 16-second interval immediately prior to the
start of the Contingency Event Recovery Period based on EMS scan rate data.
Reserve Sharing Group Reporting ACE: At any given time of measurement for the applicable
Reserve Sharing Group (RSG), the algebraic sum of the ACEs (or equivalent as calculated at such
time of measurement) of the Balancing Authorities participating in the RSG at the time of
measurement.
Contingency Reserve: The provision of capacity that may be deployed by the Balancing Authority to
respond to a Balancing Contingency Event and other contingency requirements (such as Energy
Emergency Alerts as specified in the associated EOP standard). A Balancing Authority may include
in its restoration of Contingency Reserve readiness to reduce Firm Demand and include it if, and
only if, the Balancing Authority:
x

is experiencing a Reliability Coordinator declared Energy Emergency Alert level, and

BAL-002-2 – Disturbance Control Performance - Contingency Reserve for Recovery from a Balancing Contingency Event
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x

is utilizing its Contingency Reserve to mitigate an operating emergency in accordance with
its emergency Operating Plan.

The existing definition of Contingency Reserve should be retired at midnight of the day immediately
prior to the effective date of BAL-002-2, in the jurisdiction in which the new standard is becoming
effective.
Applicable Entities
Balancing Authority
Reserve Sharing Group
Applicable Facilities
N/A
Conforming Changes to Other Standards
None
Effective Dates
BAL-002-2 shall become effective as follows:
The first day of the first calendar quarter that is six months after the date that this standard is
approved by applicable 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 six months after the date
the standard is adopted by the NERC Board of Trustees’, or as otherwise provided for in that
jurisdiction.
Justification
The six-month period for implementation of BAL-002-2 will provide ample time for Balancing
Authorities to make necessary modifications to existing software programs to ensure compliance.
Retirements

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BAL-002-0, Disturbance Control Performance, and BAL-002-1, Disturbance Control Performance should
be retired at midnight of the day immediately prior to the Effective Date of BAL-002-2 in the particular
jurisdiction in which the new standard is becoming effective.

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Implementation Plan

Project 2010-14.1 Balancing Authority Reliability-based Controls
- Reserves
Implementation Plan for BAL-002-2 – Disturbance Control Performance - Contingency Reserve for
Recovery from a Balancing Contingency Event
Approvals Required
BAL-002-2 – Disturbance Control Performance - Contingency Reserve for Recovery from a Balancing
Contingency Event
Prerequisite Approvals
None
Revisions to Glossary Terms
The following definitions shall become effective when BAL-002-2 becomes effective:
Balancing Contingency Event: Any single event described in Subsections (A), (B), or (C) below, or
any series of such otherwise single events, with each separated from the next by less than one
minute or less.
A. Sudden loss of generation:
a. Due to
i. unitUnit tripping, or
ii. lossLoss of generator Facility resulting in isolation of the generator from the
Bulk Electric System or from the responsible entity’s Systemelectric system,
or
iii. suddenSudden unplanned outage of transmission Facility;
b. And, that causes an unexpected change to the responsible entity’s ACE;
B. Sudden loss of an Import, due to forced outage of transmission equipment that causes an
unexpected imbalance between generation and Demandload on the Interconnection.
C. Sudden restoration of a Demandload that was used as a resource that causes an
unexpected change to the responsible entity’s ACE.

Most Severe Single Contingency (MSSC): The Balancing Contingency Event, due to a single
contingency as identified and maintained in the system models within the Reserve Sharing Group
(RSG) or a Balancing Authority’s area that is not part of a Res area that is not part of a Reserve
Sharing Group, that would result in the greatest loss (measured in MW) of resource output used by
the RSGReserve Sharing Group (RSG) or a Balancing Authority that is not participating as a member
of a RSG at the time of the event to meet Firm Demandfirm system load and export obligation
(excluding export obligation for which Contingency Reserve obligations are being met by the Sink
Balancing Authority).
Reportable Balancing Contingency Event: Any Balancing Contingency Event occurring within a
one-minute interval of an initial sudden decline in ACE based on EMS scan rate data that
resultsresulting in a loss of MW output less than or equal to the Most Severe Single Contingency,
and greater than or equal to the lesser amount of: (i) 80% of the Most Severe Single Contingency,
or (ii) the amount listed below for the applicable Interconnection., and occurring within a oneminute interval of the initial sudden decline in ACE based on EMS scan rate data. Prior to any given
calendar quarter, the 80% threshold may be reduced by the responsible entity upon written
notification to the Regional Entity.
x

Eastern Interconnection – 900 MW

x

Western Interconnection – 500 MW

x

ERCOT – 800 MW

x

Quebec – 500 MW

Contingency Event Recovery Period: A period that beginsbeginning at the time that the resource
output begins to decline within the first one-minute interval ofthat defines a Reportable Balancing
Contingency Event, and extends for fifteen minutes thereafter.
Contingency Reserve Restoration Period: A period not exceeding 90 minutes following the end of
the Contingency Event Recovery Period.
Pre-Reporting Contingency Event ACE Value: The average value of Reporting ACE, or Reserve
Sharing Group Reporting ACE when applicable, in the 16-second interval immediately prior to the
start of the Contingency Event Recovery Period based on EMS scan rate data.
Reserve Sharing Group Reporting ACE: At any given time of measurement for the applicable
Reserve Sharing Group (RSG),, the algebraic sum of the ACEs (or equivalent as calculated at such
time of measurement) of the Balancing Authorities participating in the RSGReserve Sharing Group
at the time of measurement.
Contingency Reserve: The provision of capacity that may be deployed by the Balancing Authority to
respond to a Balancing Contingency Event and other contingency requirements (such as Energy

BAL-002-2 – Disturbance Control Performance - Contingency Reserve for Recovery from a Balancing Contingency Event
JulyJanuary 2015

2

Emergency Alerts as specified in the associated EOP standard). A Balancing Authority may include
in its restoration of Contingency Reserve readiness to reduce Firm Demand and include it if, and
only if, the Balancing Authority:The capacity may be provided by resources such as Demand-Side
Management (DSM), Interruptible Load and unloaded generation.
x

is experiencing a Reliability Coordinator declared Energy Emergency Alert level, and

x

is utilizing its Contingency Reserve to mitigate an operating emergency in accordance with
its emergency Operating Plan.

The existing definition of Contingency Reserve should be retired at midnight of the day immediately
prior to the effective date of BAL-002-2, in the jurisdiction in which the new standard is becoming
effective.
Applicable Entities
Balancing Authority
Reserve Sharing Group
Applicable Facilities
N/A
Conforming Changes to Other Standards
None
Effective Dates
BAL-002-2 shall become effective as follows:
The first day of the first calendar quarter that is six months after the date that this standard is
approved by applicable 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 six months after the date
the standard is adopted by the NERC Board of Trustees’, or as otherwise provided for in that
jurisdiction.
Justification

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The six-month period for implementation of BAL-002-2 will provide ample time for Balancing
Authorities to make necessary modifications to existing software programs to ensure compliance.
Retirements
BAL-002-0, Disturbance Control Performance, and BAL-002-1, Disturbance Control Performance should
be retired at midnight of the day immediately prior to the Effective Date of BAL-002-2 in the particular
jurisdiction in which the new standard is becoming effective.

BAL-002-2 – Disturbance Control Performance - Contingency Reserve for Recovery from a Balancing Contingency Event
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Unofficial Comment Form

Project 2010-14.1 Phase 1 of Balancing Authority
Reliability-based Controls: Reserves
BAL-002-2
Do not use this form for submitting comments. Use the electronic form to submit comments on the
proposed revisions to BAL-002-2 Disturbance Control Performance - Contingency Reserve for Recovery
from a Balancing Contingency Event. The electronic form must be submitted by 8 p.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

Since loss of generation occurrences so often impacts all Balancing Authorities throughout an
Interconnection, BAL-002 was created to specify recovery actions and time frames. The original
Standards Authorization Request (SAR) approved by the Industry presumes there is presently sufficient
contingency reserve in all the North American Interconnections. The underlying goal of the SAR was to
update the Standard to make the measurement process more objective and to provide information to
the Balancing Authority or Reserve Sharing Group such that the parties would better understand the use
of contingency reserve to balance resources and demand following a Reportable Contingency Event. The
primary objective of BAL-002-2 is to measure the success of recovering from contingency events.
Based on comments received from industry stakeholders the drafting team made the following
modifications to the draft standard:
x

Modified Requirement R1 to provide additional clarity.

x

Modified Requirement R2 to provide for development of a process for Contingency Reserve to be
included in an entity’s Operating Plan.

x

Added Requirement R3 to provide for the restoration of Contingency Reserve.

x

Modified the rationale supporting Requirements R1 and R2 to provide additional information.

x

Added rationale to support Requirement R3.

x

Added rationale to support the modifications made to the definition of Contingency Reserve.

x

Modified the BAL-002-2 Background Document to provide additional clarity.

Questions

1. Please provide any issues you have on this draft of the BAL-002-2 standard and offer a proposed
solution for those issues.
Comments:

Unofficial Comment Form
Project 2010-14.1 Phase 1 of BARC | July-August 2015

2

BAL-002-2
Background Document
July 2015

BAL-002-2 - Background Document
July 2015

1

Table of Contents
Introduction .................................................................................................................................... 3
Rationale by Requirement .............................................................................................................. 7
Requirement 1 ............................................................................................................................ 7
Requirement 2 .......................................................................................................................... 14
Requirement 3 .......................................................................................................................... 15

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Disturbance Control Performance - Contingency Reserve for Recovery From a Balancing
Contingency Event Standard Background Document

Introduction
The revision to NERC Policy Standards in 1996 created a Disturbance Control Standard (DCS). It
replaced B1 [Area Control Error (ACE) must return to zero within 10 minutes following a
disturbance] and B2 (ACE must start to return to zero in 1 minute following a disturbance) with
a standard that states: ACE must return to either zero or a pre-disturbance value of ACE within
15 minutes following a reportable disturbance. Balancing Authorities were required to report
all disturbances equal to or greater than 80% of the Balancing Authority’s Most Severe Single
Contingency (MSSC).
BAL-002 was created to replace portions of Policy 1. It measures the ability of an applicable
entity to recover from a reportable event with the deployment of reserve. The reliable
operation of the interconnected power system requires that adequate capacity and energy be
available to maintain scheduled frequency and avoid loss of firm load following loss of
transmission or generation contingencies. This capacity (Contingency Reserve) is necessary to
replace capacity and energy lost due to forced outages of generation or transmission
equipment. The design of BAL-002 and Policy 1 was predicated on the Interconnection’s
operating under normal conditions, and the requirements of BAL-002 assured recovery from
single contingency (N-1) events.
This document provides background on the development and implementation of BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event. This document explains
the rationale and considerations for the requirements and their associated compliance
information. BAL-002-2 was developed to fulfill the NERC Balancing Authority Controls (Project
2007-05) Standard Authorization Request (SAR), which includes the incorporation of the FERC
Order 693 directives. The original SAR, approved by the industry, presumes there is presently
sufficient Contingency Reserve in all the North American Interconnections. The underlying goal
of the SAR was to update the standard to make the measurement process more objective and
to provide information to the Balancing Authority or Reserve Sharing Group, such that the
parties would better understand the use of Contingency Reserve to balance resources and
demand following a Reportable Balancing Contingency Event.
Currently, the existing BAL-002-1 standard contains Requirements specific to a Reserve Sharing
Group which the drafting team believes are commercial in nature and a contractual
arrangement between the reserve sharing group parties. BAL-002-2 is intended to measure the
successful deployment of contingency reserve by responsible entities. Relationships between
the entities should not be part of the performance requirements, but left up to a commercial
transaction.
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Disturbance Control Performance - Contingency Reserve for Recovery From a Balancing
Contingency Event Standard Background Document

Clarity and specifics are provided with several new definitions. Additionally, the BAL-002-2
eliminates any question about who is the applicable entity and assures that the applicable
entity is held responsible for the performance requirement. The drafting team’s goal was to
have BAL-002-2 be solely a performance standard. The primary objective of BAL-002-2 is to
ensure that the applicable entity is prepared to balance resources and demand and to return its
ACE to defined values (subject to applicable limits) following a Reportable Balancing
Contingency Event.
As proposed, this standard is not intended to address events greater than a Responsible Entity’s
Most Severe Single Contingency. These large multi-unit events, although unlikely, do occur.
Many interactions occur during these events and Balancing Authorities (BAs) and Reserve
Sharing Groups must react to these events. However, requiring a recovery of ACE within a
specific time period is much too simple a methodology to adequately address all of these
interactions. The suite of NERC Standards work together to ensure that the Interconnections
are operated in a safe and reliable manner. It is not just one standard, rather it is the
combination of the BAL-001-2 standard (in which R2 requires operation within an ACE
bandwidth based on interconnection frequency), TOP-007, and EOP-002, which collectively
address issues when large events occur.
x

The Balancing Authority ACE Limit (BAAL) in R2 of BAL-001-2 looks at Interconnection
frequency to provide the BA a range in which the BA should strive to operate as well as
a 30-minute period to address instances when the BA is outside of that range. If an
event larger than the BA’s MSSC occurs, the BAAL will likely change to a much tighter
control limit based on the change in interconnection frequency. The 30-minute limit
under the BAAL allows the BA (and its RC) time to quickly evaluate the best course of
action and then react in a reasonable manner. BAAL also ensures the Responsible Entity
balances resources and demand when events occur of less magnitude than a Reportable
Balancing Contingency. In addition R1 of BAL-001-2 requires the BA to respond to
assure Control Performance Standard 1 (CPS1) is met. This may prompt the BA to
respond in some circumstances in less than 10 minutes.

x

The TOP-007 standard addresses transmission line loading. Members of the BAL-002-2
drafting team are aware of instances (typically N-2 or less) that could cause transmission
overloads if certain units were lost and reserves responded.

x

Under EOP-002, if the BA does not believe that it can meet certain parameters, different
rules are implemented.

Because of the potential for significant unintended consequences that could occur under a
requirement to activate all reserves, the drafting team recommends to the industry that the
revised BAL-002-2 address only events which are planned for (N-1) and not any loss of
resource(s) that would exceed MSSC. Therefore, the definitions and Requirements under BAL002-2 exclude events greater than the MSSC. This provides clarity of Requirements, supports
BAL-002-2 - Background Document
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Disturbance Control Performance - Contingency Reserve for Recovery From a Balancing
Contingency Event Standard Background Document
reliable operation of the Bulk Electric System and allows other standards to address events of
greater magnitude and complexity.
Within NERC’s State of Reliability Report, ALR2-5 “Disturbance Control Events Greater Than the
Most Severe Single Contingency” has been tracked and reported since 2006. For the period
2006 to 2011 there were 90 disturbance events that exceeded the MSSC, with the highest in
any given year being 24 events. Evaluation of the data illustrates events greater than MSSC
occur very infrequently, and the drafting team believes their exclusion will not have any
adverse impact on reliability.
The metric reports the number of DCS events greater than MSSC, regardless of the size of a
Balancing Authority or RSG and of the number of reporting entities within a Regional Entity. A
small Balancing Authority or RSG may have a relatively small MSSC. As such, a high number of
DCS events greater than MSSC may not indicate a reliability problem for the reporting Regional
Entity, but may indicate an issue for the respective Balancing Authority or RSG. In addition,
events greater than MSSC may not cause a reliability issue for a BA, RSG or Regional Entity that
has more stringent standards which require contingency reserve greater than MSSC.

Background
Reliably balancing an Interconnection requires frequency management and all of its aspects.
Inputs to frequency management include Tie-Line Bias Control, Area Control Error (ACE), and
the various Requirements in NERC Resource and Demand Balancing Standards, specifically BAL001-2 Real Power Balancing Control Performance and BAL-003-1 Frequency Response and
Frequency Bias Setting.
Balancing Contingency Event
BAL-002-2 applies during real-time operations to ensure the Balancing Authority or Reserve
Sharing Group balance resources and demand by returning its Area Control Error to defined
values following a Reportable Balancing Contingency Event.
The drafting team included a specific definition for a Balancing Contingency Event to eliminate
any confusion and ambiguity. The prior version of BAL-002 was broad and could be interpreted
in various ways leaving the ability to measure compliance in the eye of the beholder. Including
the specific definition allows the Responsible Entity to fully understand how to perform and
meet compliance. Also, FERC Order 693 (at P355) directed entities to include a Requirement
that measures response for any event or contingency that causes a frequency deviation. By
developing a specific definition that depicts the events causing an unexpected change to the
Responsible Entity’s ACE, the necessary response requirements assure the intent of the FERC
requirement is met.
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Disturbance Control Performance - Contingency Reserve for Recovery From a Balancing
Contingency Event Standard Background Document
The definitions of Reportable Balancing Contingency Event and Contingency Event Recovery
Period work together to specify the timing requirements for recoveries from Reportable
Balancing Contingency Events. A Balancing Contingency Event that is not a Reportable
Balancing Contingency Event may impact the compliance requirement for the Reportable
Balancing Contingency Event which occurs after it, because the megawatts lost for both may
exceed the Most Severe Single Contingency. Also, a subsequent Balancing Contingency Event
may occur during the Contingency Event Recovery Period of a Reportable Balancing
Contingency Event, affecting the ACE recovery requirement of the initial event. The drafting
team struggled with associating any specific time window for the megawatt loss to occur within
for an event to qualify as a Balancing Contingency Event. The term sudden implies an
unexpected occurrence in the definition of a Balancing Contingency Event, and the Responsible
Entity should use its best judgment in applying any time criterion to Balancing Contingency
Events that do not qualify as Reportable Balancing Contingency Events.
Most Severe Single Contingency
The Most Severe Single Contingency (MSSC) term has been widely used within the industry;
however, it has never been defined. In order to eliminate a wide range of definitions, the
drafting team has included a specific definition designed to fulfill the needs of the standard. In
addition, in order to meet FERC Order No. 693 (at P356), to develop a continent-wide
contingency reserve policy, it was necessary to establish a definition of MSSC.
When an entity determines its MSSC, the review needs to include the largest loss of resource
that might occur for either generation or transmission loss. If the loss of transmission causes
the loss of generation and load, the size of that event would be the net change. Since the size of
an event where both load and generation are lost due to the loss of the transmission would be
less than just the loss of the generator, this event is unlikely to be the entity’s MSSC. Also, note
here that the drafting team removed the previous requirement to review the MSSC at least
annually. An entity should know what its MSSC is at all times. Therefore, an annual review is no
longer required
Contingency Reserve
Most system operators generally have a good understanding of the need to balance resources
and demand and return their Area Control Error to defined values following a Reportable
Balancing Contingency Event. However, the existing Contingency Reserve definition is focused
primarily on generation and not sufficiently on Demand-Side Management (DSM). In order to
meet FERC Order No. 693 (at P 356) to include a requirement that explicitly allows DSM to be
used as a resource for contingency reserve, the drafting team elected to expand the definition
of Contingency Reserve to explicitly include capacity associated with DSM.
Additionally, conflict existed between BAL-002 and EOP-002 as to when an entity could deploy
or restore its contingency reserve. EOP-002 also applies during the real-time operations time
horizon and addresses capacity and energy emergencies. Given that an entity and/or event can
transition suddenly from normal operations (BAL-002) into emergency operations (EOP-002),
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Disturbance Control Performance - Contingency Reserve for Recovery From a Balancing
Contingency Event Standard Background Document
this transitional seam must be explicitly addressed in order to provide clarity to responsible
entities regarding the actions to be taken.
To eliminate the possible conflict and to assure BAL-002 and EOP-002 work together and
complement each other, the drafting team clarified the existing definition of Contingency
Reserve. The conflict arises since the actions required by Energy Deficient Entities before
declaring either an Energy Emergency Alert 2 or an Energy Emergency Alert 3 include
deployment of all Operating Reserve which includes Contingency Reserve. Conversely, an
Energy Deficient Entity may need to declare either an Energy Emergency Alert 2 or an Energy
Emergency Alert 3, before incurring a Balancing Contingency Event. The definition of
Contingency Reserve now allows for deploying capacity to respond to a Balancing Contingency
Event and other contingency requirements such as Energy Emergency Alerts. Readiness to
reduce Firm Demand during the Contingency Reserve Restoration Period during an Energy
Emergency Alert should another Contingency Event occur is proposed for inclusion in the
definition of Contingency Reserve. The Responsible Entity should have processes and
procedures for direct control over the Firm Demand in place for it to be considered Contingency
Reserves prior to the event during an Energy Emergency Alert.
For additional technical justification for exemption from R1 to facilitate transitioning from
normal operations into emergency operations please refer to Attachment 2.
Reserve Sharing Group Reporting ACE
The drafting team elected to include this definition to provide clarity for measurement of
compliance of the appropriate Responsible Entity. Additionally, this definition is necessary
since the drafting team has eliminated R5.1 and R5.2 that are in the existing standard. R5.1 and
R5.2 mix definitions with performance. The drafting team has included all the performance
requirements in the proposed standards R1 and R2, and therefore has added the definition of
Reserve Sharing Group Reporting ACE.
Other Definitions
Other definitions have been added or modified to assure clarification within the standard and
requirements.

Rationale by Requirement
Requirement 1
The Responsible Entity experiencing a Reportable Balancing Contingency Event shall:

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Disturbance Control Performance - Contingency Reserve for Recovery From a Balancing
Contingency Event Standard Background Document
1.1. within the Contingency Event Recovery Period, demonstrate recovery by
returning its Reporting ACE to at least the recovery value of:
x

zero (if its Pre-Reporting Contingency Event ACE Value was positive or equal
to zero); however, any Balancing Contingency Event that occurs during the
Contingency Event Recovery Period shall reduce the required recovery: (i)
beginning at the time of, and (ii) by the magnitude of, such individual
Balancing Contingency Event,

or,
x

its Pre-Reporting Contingency Event ACE Value (if its Pre-Reporting
Contingency Event ACE Value was negative); however, any Balancing
Contingency Event that occurs during the Contingency Event Recovery Period
shall reduce the required recovery: (i) beginning at the time of, and (ii) by the
magnitude of, such individual Balancing Contingency Event.

1.2. document all Reportable Balancing Contingency Events using CR Form 1.
1.3. deploy Contingency Reserve, within system constraints, to respond to all
Reportable Balancing Contingency Events, however, it is not subject to
compliance with Requirement R1 part 1.1 if:
1.3..1 the Responsible Entity is:
x

experiencing a Reliability Coordinator declared Energy Emergency
Alert Level, and

x

utilizing its Contingency Reserve to mitigate an operating emergency in
accordance with its emergency Operating Plan, and

x

the Responsible Entity has depleted its Contingency Reserve to a level
below its Most Severe Single Contingency

or,
1.3.2 the Responsible Entity experiences:
x

multiple Contingencies where the combined MW loss exceeds its
Most Severe Single Contingency and that are defined as a single
Balancing Contingency Event, or

x

multiple Balancing Contingency Events within the sum of the time
periods defined by the Contingency Event Recovery Period and
Contingency Reserve Restoration Period whose combined magnitude
exceeds the Responsible Entity's Most Severe Single Contingency.

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Disturbance Control Performance - Contingency Reserve for Recovery From a Balancing
Contingency Event Standard Background Document

Background and Rationale
Requirement R1 reflects the operating principles first established by NERC Policy 1. Its
objective is to assure the Responsible Entity balances resources and demand and returns its
Reportable Area Control Error (ACE) to defined values (subject to applicable limits) following a
Reportable Balancing Contingency Event. It requires the Responsible Entity to recover from
events that would be less than or equal to the Responsible Entity’s MSSC. It establishes
recovery and restoration timeframes the Responsible Entity must demonstrate in a compliance
evaluation. It is intended to eliminate the ambiguities and questions associated with the
existing standard. In addition, it allows Responsible Entities to have a clear way to demonstrate
compliance and support the Interconnection to the full extent of its MSSC.
By including new definitions, and modifying existing definitions, and the above R1, the drafting
team believes it has successfully fulfilled the requirements of FERC Order No. 693 (at P 356) to
include a requirement that explicitly allows DSM to be used as a resource for Contingency
Reserve. It also recognizes that the loss of transmission as well as generation may require the
deployment of Contingency Reserve.
Additionally, R1 is designed to assure the applicable entity uses reserve to cover a Reportable
Balancing Contingency Event or the combination of any previous Balancing Contingency Events
that have occurred within the specified period, to address the Order’s concern that the
applicable entity is responding to events and performance is measured. The Reportable
Balancing Contingency Event definition, along with R1, allows for measurement of
performance.
In addition, the standard drafting team (SDT) through R1 Part 1.3 has clearly identified when R1
is not applicable. By including R1 Part 1.3.1, the proposed standard eliminates the existing
conflict with the EOP Standards and further addresses the outstanding interpretation. By
clearly stating when R1 is not applicable or does not apply, it eliminates any auditor
interpretation and allows the Responsible Entity to perform the function in a reliable manner.
Requirement R1 does not apply when an entity experiences a Balancing Contingency Event that
exceeds its MSSC (which includes multiple Balancing Contingency Events as described in R1 part
1.3.2) because a fundamental goal of the SDT is to assure the Responsible Entity has enough
flexibility to maintain service to load while managing reliability. Also, the SDT’s intent is to
eliminate any potential overlap or conflict with any other NERC Reliability Standard to eliminate
duplicative reporting, and other issues.
The drafting team used data supplied by the Consortium for Electric Reliability Technology
Solutions (CERTS) to help determine all events that have an impact on frequency. Data that
was compiled by CERTS to provide information on measured frequency events is presented in
Attachment 1. Analyzing the data, reveals events of 100 MW or greater would capture all
frequency events for all interconnections. However, at a 100 MW reporting threshold, the
number of events reported would significantly increase with no reliability gain since 100 MW is
more reflective of the outlying events, especially on larger interconnections.
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Disturbance Control Performance - Contingency Reserve for Recovery From a Balancing
Contingency Event Standard Background Document
The goal of the drafting team was to design a continent-wide standard to capture the majority
of the events that impact frequency. After reviewing the data and industry comments, the SDT
elected to establish reporting threshold minimums for each respective Interconnection. This
assures the requirements of FERC Order No. 693 are met. The reportable threshold was
selected as the lesser of 80% of the applicable entity’s Most Severe Single Contingency or the
following values for each respective Interconnection:
x
x
x
x

Eastern Interconnection – 900 MW
Western Interconnection – 500 MW
ERCOT – 800 MW
Quebec – 500 MW

Additionally, the drafting team used only loss of resource events for purposes of determining
the above thresholds.
Violation Severity Levels
In the Violation Severity Levels for Requirement R1, the impact of the Responsible Entity
recovering from a Reportable Balancing Contingency Event depends on the percentage of
desired recovery achieved.
Compliance Calculation
It is important to note that R1 adjusts the required recovery value of Reporting ACE for any
other Balancing Contingency Events that occur during the Contingency Event Recovery Period.
However, to determine compliance score for compliance with R1, the measured contingency
reserve response (instead of the required recovery value of Reporting ACE) is adjusted for any
other Balancing Contingency Events that occur during the Contingency Event Recovery Period.
Both methods of adjustment are mathematically equivalent. Accordingly, the measured
contingency reserve response is computed and compared with the MW lost as follows
(assuming all resource loss values, i.e. Balancing Contingency Events, are positive) to measure
compliance 1:
ͻ

The measured contingency reserve response is equal to one of the following:
o If the Pre-Reportable Contingency Event ACE Value is greater than or equal
to zero, then the measured contingency reserve response equals (a) the

1

In adjusting for the adverse impact of rapidly succeeding (i.e. “near”) Events on a Responsible Entity’s Recovery
from an Event, the SDT thought it more prudent to adjust for future near Events rather than for past near Events
because the future Events place an added burden on performance, while adjusting for the past Events instead
lowers the performance requirement. To adjust for both future and past Events amounts to double dealing
because an Event is subsequent to a prior near Event, and both Events would be serving to relieve Recovery from
each other. The SDT allowed only for the extreme case of exempting from recovery prior near Events that
combined exceed MSSC.

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megawatt value of the Reportable Balancing Contingency Event plus (b) the
most positive ACE value within its Contingency Event Recovery Period (and
following the occurrence of the last subsequent event, if any) plus (c) the
sum of the megawatt losses of the subsequent Balancing Contingency Events
occurring within the Contingency Event Recovery Period of the Reportable
Balancing Contingency Event.
o If the Pre-Reportable Contingency Event ACE Value is less than zero, then the
measured contingency reserve response equals (a) the megawatt value of
the Reportable Balancing Contingency Event plus (b) the most positive ACE
value within its Contingency Event Recovery Period (and following the
occurrence of the last subsequent event, if any) plus (c) the sum of the
megawatt losses of subsequent Balancing Contingency Events occurring
within the Contingency Event Recovery Period of the Reportable Balancing
Contingency Event, minus (d) the Pre-Reportable Contingency Event ACE
Value.
ͻ Compliance is computed as follows on CR Form 1 in order to document all
Balancing Contingency Events used in compliance determination:
ƒ

If the measured contingency reserve response is greater than or
equal to the megawatts lost, then the Reportable Balancing
Contingency Event Compliance equals 100 percent.

ƒ

If the measured contingency reserve response is less than or equal to
zero, then the Reportable Balancing Contingency Event Compliance
equals 0 percent.

ƒ

If the measured contingency reserve response is less than the
megawatts lost but greater than zero, then the Reportable Balancing
Contingency Event Compliance equals 100% * (1 – ((megawatts lost –
measured contingency reserve response) / megawatts lost)).

The above computations can be expressed mathematically in the following 5 sequential steps,
labeled as [1-5], where:
ACE_BEST – most positive ACE during the Contingency Event Recovery Period occurring after
the last subsequent event, if any (MW)
ACE_PRE - Pre-Reportable Contingency Event ACE Value (MW)
COMPLIANCE - Reportable Balancing Contingency Event Compliance percentage (0 - 100%)
MEAS_CR_RESP - measured contingency reserve response for the Reportable Balancing
Contingency Event (MW)
MSSC – Most Severe Single Contingency (MW)
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MW_LOST - megawatt loss of the Reportable Balancing Contingency Event (MW)
SUM_SUBSQ - sum of the megawatt losses of subsequent Balancing Contingency Events
occurring within the Contingency Event Recovery Period of the Reportable Balancing
Contingency Event (MW)
If ACE_PRE is greater than or equal to 0, then
MEAS_CR_RESP = MW_LOST +ACE_BEST + SUM_SUBSQ [1]
If ACE_PRE is less than 0, then
MEAS_CR_RESP = MW_LOST +ACE_BEST + SUM_SUBSQ – ACE_PRE [2]
If MEAS_CR_RESP is greater than or equal to MW_LOST, then
COMPLIANCE = 100 [3]
If MEAS_CR_RESP is less than or equal to 0, then
COMPLIANCE = 0 [4]
If MEAS_CR_RESP is greater than 0, and, MEAS_CR_RESP is less than MW_LOST, then
COMPLIANCE = 100 * (1 – ((MW_LOST – MEAS_CR_RESP)/ MW_LOST)) [5]

The Decision Tree flow diagram for DCS below, provides a visualization of the logic flow for a
Reportable Balancing Contingency Event. It includes decision blocks for initial event
determination, subsequent event determination, and checking for MSSC exceedance which
should assist the Responsible Entity with Event Recovery and analysis.

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BAAL and
IROL

Resource Loss
> Reporting
Threshold

DCS Real
Time

DCS Off
Line
Reporting

N

Sudden?

Y

Start 15
Minute
Recovery
Subsequent
Events?

Y

N

Decision Tree for DCS

Make Best
Efforts on
Recovery

> MSSC

Adjust
Calculations

Y

13

N

If IROL or
BAAL
Exceeded, Begin
30 Min Recover

Complete
Form

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Requirement 2
R2.

Each Responsible Entity shall develop, review and maintain annually, and implement
an Operating Process as part of its Operating Plan to determine its Most Severe
Single Contingency and to have Contingency Reserve equal to, or greater than the
Responsible Entity’s Most Severe Single Contingency available for maintaining
system reliability.

Background and Rationale
R2 establishes a uniform continent-wide contingency reserve policy in the form of a
requirement that a Responsible Entity implement an Operating Plan that assures Contingency
Reserve be at least equal to the applicable entity’s Most Severe Single Contingency and a
definition of Most Severe Single Contingency. Its goal is to assure that the Responsible Entity
will have sufficient Contingency Reserve that can be deployed to meet R1.
FERC Order 693 (at P356) directed BAL-002 to be developed as a continent-wide contingency
reserve policy. R2 fulfills the requirement associated with the required amount of contingency
reserve a Responsible Entity must have available to respond to a Reportable Balancing
Contingency Event. Within FERC Order 693 (at P336) the Commission noted that the
appropriate mix of operating reserve, spinning reserve and non-spinning reserve should be
addressed. However, the Order predated the approval of the new BAL-003, which addresses
frequency responsive reserve and the amount of frequency response obligation. With the
development of BAL-003, and the associated reliability performance requirement, the SDT
believes that, with R2 of BAL-002 and the approval of BAL-003, the Commission’s goals of a
continent-wide contingency reserves policy is met. The suites of BAL standards (BAL-001, BAL002, and BAL-003) are all performance-based. With the suite of standards and the specific
requirements within each respective standard, a continent-wide contingency policy is
established.
The Responsible Entity’s Operating Plan will address the process by which Contingency
Reserves greater than or equal to the Most Severe Single Contingency are available in Realtime. Once an entity utilizes its contingency reserve, Requirement R3 addresses restoration of
the reserves.

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Requirement 3
R3.

Each Responsible Entity, following a Reportable Balancing Contingency Event, shall
restore its Contingency Reserve to at least its Most Severe Single Contingency,
before the end of the Contingency Reserve Restoration Period, but any Balancing
Contingency Event that occurs before the end of a Contingency Reserve Restoration
period resets the beginning of the Contingency Event Recovery Period.

Background and Rationale
Requirement R3 establishes the restoration of Contingency Reserves following Reportable
Balancing Contingency Events. This requirement addresses the need to be prepared for future
Balancing Contingency Events. Contingency Reserves must be restored to at least the minimum
required amount, the Most Severe Single Contingency, to assure that the next event for which
an entity plans is expected to be covered if the event occurs. Contingency Reserves must be
restored within the Contingency Reserve Restoration Period which is defined as a period not
exceeding 90 minutes following the end of the Contingency Event Recovery Period, which is 15
minutes.

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Attachment 1
NERC Interconnections 2009-2013
Frequency Events Loss MW Statistics

For: NERC BARC Standard Drafting Team
Prepared by: CERTS
Date: October 15, 2013

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Attachment 2
Technical Justification for Applicability
of BAL-002 During Emergency Alerts

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Technical Justification for Applicability of BAL-002
During Energy Emergency Alerts
I.

INTRODUCTION

The Balancing Authority Reliability-based Controls standard drafting team (BARC SDT) has
identified a conflict between NERC Reliability Standards BAL-002 and EOP-002 that
unnecessarily requires arbitrary interruption of Firm Load. In order to address this issue, the
BARC SDT is recommending that Standard BAL-002-2 not be enforceable during an Energy
Emergency Alert (EEA) event where the EEA process requires the use of Contingency Reserve to
maintain load service. 2 This document provides support for this recommendation and an
overview of reliable frequency management on the North American Interconnections.
II.

BACKGROUND

Reliably balancing an Interconnection requires frequency management and all of its aspects.
Inputs to frequency management include Tie-Line Bias Control, Area Control Error (ACE), and
the various Requirements in NERC Resource and Demand Balancing Standards, specifically BAL001-2 Real Power Balancing Control Performance and BAL-003-1 Frequency Response and
Frequency Bias Setting.
Reliability Standard BAL-002 applies during the real-time operations time horizon and
addresses the balancing of resources and demand following a disturbance. Reliability Standard
EOP-002 also applies during the real-time operations time horizon and addresses capacity and
energy emergencies. Given that an entity and/or event can transition suddenly from normal
operations into emergency operations (EOP-002) where Contingency Reserve maintained under
BAL-002 may be utilized to serve Firm Load, this transitional seam must be explicitly addressed
in order to provide clarity to responsible entities regarding the actions to be taken. The
proposed applicability of BAL-002 is designed to address this issue.
III.

LEGACY REQUIREMENTS

The Resource and Demand Balancing (BAL) standards include both requirements that have a
sound technical basis and legacy requirements that the industry has used for years but fail to

2

The proposed applicability section states: “Applicability is determined on an individual Reportable Balancing
Contingency Event basis, but the Responsible Entity is not subject to compliance during periods when the
Responsible Entity is in an Energy Emergency Alert Level under which Contingency Reserves have been activated.”

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have a sound technical basis. NERC began replacing these legacy requirements with technically
based requirements starting with the Control Performance Standard1 (CPS1). Both Control
Performance Standard2 (CPS2) and the Disturbance Control Standard (DCS) remain in the
legacy category. The following are specific concerns associated with these requirements.
o When CPS1 was implemented to replace A1/A2, previous requirements were
modified so that CPS1 would apply at all times including the (disturbance)
periods where DCS is applicable, not just during normal operations/periods. So
DCS is not the only standard governing disturbance conditions.
o The Disturbance Control Standard (DCS) and its precursor B1/B2 have been
unique in requiring immediate action by the Balancing Authority (BA), in this
case to address unexpected imbalances within defined limits.
o DCS, albeit results-based in its current form, was initially designed to measure
the utilization of Contingency Reserve to address a loss of resource within the
defined limits. In its results-based form it assumed that implementing sufficient
Contingency Reserves as needed to comply with the recovery requirement
would be a reasonably equitable minimum quantity for all BAs participating in
interconnected operation.
o DCS is based upon ACE recovery to the lower of pre-disturbance ACE or zero. A
Balancing Authority which might be under-generating prior to a generation loss,
could lose a generating unit and under DCS be deemed compliant if it returned
ACE to its pre-disturbance state, though it could still be depressing
Interconnection frequency.
o As DCS recovery from a reportable event must occur within a 15-minute period,
it is possible for a Balancing Authority’s ACE to again go negative after that time,
with a similar impact on Interconnection frequency.
o Since CPS2 allows a BA to be unaccountable for approximately 74 hours of
operation in a 31-day month, an imbalance condition may persist and negatively
impact Interconnection frequency for many hours 3.
o When ACE is modulated by frequency, “significant” losses are defined not only
by the size of the event causing an ACE deviation, but also contingent on the
deviation of Interconnection frequency from Scheduled Frequency.
IV.

3

TIE-LINE BIAS FREQUENCY CONTROL AND ACE

Reliability-Based Control v3, Standard Authorization Request Form, November 7, 2007.

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Tie-Line Bias Frequency Control is implemented on the North American Interconnections
through the use of the ACE Equation. 4 In general, ACE is the term used to determine the loadgeneration imbalance that is being contributed by each Balancing Authority (BA) on an
Interconnection. ACE is a powerful indicator, because it indicates the imbalance within the
boundaries of a single BA, thus defining the Secondary Control responsibilities for that BA and,
therefore, the control action that would return ACE to zero. ACE includes the Frequency Bias
Setting term, which allows the Primary Frequency Control to be a shared service throughout a
multi-BA Interconnection, while assigning to each individual BA the specific responsibilities of
maintaining its own Secondary Frequency Control.
In summary, ACE only provides guidance with respect to Secondary Frequency Control and
does not indicate or provide any direct measure of Primary Frequency Control, and only reflects
the estimated Frequency Response as represented by the Frequency Bias Setting term. NERC
Requirements and supporting documentation for Frequency Response (Primary Frequency
Control) are included in BAL-003-1 Frequency Response and Frequency Bias Setting standard.
More detail on Tie-Line Bias Frequency Control and ACE is attached. 5
V.

CONTROL PERFORMANCE STANDARD1 (CPS1)

Prior to the development of CPS1, the industry assumed that, "It is impossible, however, to
use frequency deviation to identify the specific control area (sic, i.e. BA) with the under- or
over-generation creating the frequency deviation…".3 In the 1990's the development of CPS1
demonstrated that not only was it possible to identify the specific BA creating the frequency
deviation, but that it is also possible not only to determine the relative contribution by each BA
to the magnitude of the frequency deviation 6, but also to determine the relative contribution of
each BA to the reliability risk caused by that deviation. In addition, the CPS1 Requirement
provided a guarantee: "If all BAs on an interconnection complied with the CPS1 Requirement,

4

Illian, Howard F., Understanding ACE, CPS1 and BAAL, Prepared for the NERC BARC Standard Drafting Team,
September 10, 2010 rev. August 19, 2014, Section 2, pp. 1-4, for a derivation of the ACE Equation and the
requirements for implementing it that are included in the definition of ACE appearing in the NERC Glossary.

5

Illian, Howard F., Frequency Control Performance Measurement and Requirements, Ernest
Orlando Lawrence Berkeley National Laboratory, December 2010, for a discussion of the
history of Frequency Control and Performance Measurement.

6

Illian, Howard F., Understanding ACE, CPS1 and BAAL, Section 2, pp. 5-10 for a derivation
of the CPS1 requirement.

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the Root Mean Squared 7 value of the frequency deviation for that Interconnection would be
less than the epsilon1 8 frequency deviation limit for that Interconnection."
CPS1 is a rolling annual average of individual measurements each averaged over oneminute, and is assessed monthly. CPS1 measures the covariance between the ACE of a BA and
the frequency deviation of the Interconnection which is equal to the sum of the ACEs of all of
the BAs. CPS1 has the great value of using the Interconnection frequency to determine the
degree to which ACE among the BAs on a multiple BA Interconnection is harming or helping
interconnection frequency. Since the frequency deviation is a measured value, the ACE of a BA
will directly affect only the CPS1 of the BA with the ACE and not the CPS1 measure of other BAs.
VI.

BALANCING AUTHORITY ACE LIMIT (BAAL)

When the Balancing Resources and Demand (BRD) standard drafting team recognized the
need for a control measure over a shorter time horizon than either CPS1 (annual) or Control
Performance Standard 2 9 (CPS2, monthly) provided, it began looking for a measure that would
allow a window for common imbalance events like a unit trip, while providing a limit on how
much frequency deviation should be allowed over that short period. After considering
numerous alternatives, BAAL was selected as the appropriate short-term measure.10,11

7

“Root Mean Squared” means the square root of the mean of the squared errors, so that
positive and negative errors do not offset each other and any shift in the mean is counted
as error.

8

“Epsilon1” is the frequency deviation limit determined for each North American
Interconnection and used by CPS1 to bound the Root Mean Squared frequency deviation.
It is 18 mHz on the Eastern, 22.8 mHz on the Western, 30 mHz on the ERCOT, and 21
mHz on the Quebec Interconnections.

9

Proposed to be replaced by BAAL under BAL-001-2, CPS2 requires the BA to move its ACE
within predefined L10 bounds when it is binding (during only 90% of the ten-minute
periods per month) without regard to whether such action helps or hurts Interconnection
frequency.

10

Illian, Howard F., Meeting the Discrete Event Measure (DEM) Objectives with the
Abnormal Operations Measure (AOM), Prepared for the NERC Balancing Resources and
Demand Standard Drafting Team, March 20, 2004.

11

Illian, Howard F., Setting the Balancing Authority ACE Limit (BAAL) for the NERC
Abnormal Operations Measure (AOM), Prepared for the NERC Balancing Resources and
Demand Standard Drafting Team, March 28, 2004.

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Considerable evaluation and Field Trials have shown that BAAL12 is a better indicator of
contributions to reliability risk of an interconnection than the magnitude of ACE alone. This
superiority, like CPS1’s, derives from the concurrent use of both ACE and frequency error in the
BAAL measure. Thus BAAL captures the relative contribution to reliability by all of the ACEs on
an interconnection and indicates where each BA stands relative to its secondary control
responsibilities and the current state of the interconnection as indicated by the frequency error
for both under- and over-frequency conditions.
VII.

INTERACTION BETWEEN STANDARDS

The drafting team has identified as an issue the existence of points where the standards are
in conflict with each other. The drafting team has attempted to address the conflicts identified,
as follows:
NERC standard EOP-002 requires a BA to use all its reserves during an Energy Emergency
Alert 2 (EEA2) or higher. The following language is found in EOP-002 Attachment 1-EOP-002:
2.6.4 Operating Reserves. Operating reserves are being utilized such that the
Energy Deficient Entity is carrying reserves below the required minimum or
has initiated emergency assistance through its operating reserve sharing
program.
The current BAL-002 specifies a minimum level reserve requirement at all times unless a
qualifying event has occurred. The drafting team noted that in the EEA process an entity is
driven to request an EEA rarely as the result of a single unit loss. In fact, an EEA declaration by
the Reliability Coordinator might result from issues that include no event that would qualify as
a Disturbance and the EEA situation could last longer than the reserve recovery period of 90
minutes. For this reason, the drafting team recommends significant changes to the standards in
question.
In addition to the identified conflict, other standards can require the activation of
contingency reserve. These include other BAL standards, IRO standards and TOP standards.
Compared to those standards, the BAL-002 standard provides the least direct measure of
reliability. Therefore, an entity should never be conflicted between applying the requirements
of BAL-002 and complying with the other standards.

12

Illian, Howard F., Understanding ACE, CPS1 and BAAL, Prepared for the NERC BARC
Standard Drafting Team, September 10, 2010 rev. August 19, 2014, Section 2, pp. 10, for
a derivation of the BAAL requirement.

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Finally, there is one overarching principal not reflected in the discussion up to this point,
namely keeping the lights on if possible. If there is a requirement to bring ACE back no matter
what, then that requirement will have the unintended consequence of shedding Firm Load,
especially during an EEA. During the EEA process, the expectation is that a BA will have firm
load ready to shed in order to meet its reserve requirement under R2 of the proposed BAL-002
standard. However, if the BAL-002 standard also requires the entity to meet R1 during the EEA,
entities will shed firm load to restore ACE to its pre-contingency level, regardless of the lack of
any reliability issues. In other words, frequency could be settling at or very near 60 Hz, no
transmission lines are overloaded as determined by the TOP standards, and the entity is
operating within the parameters defined in BAL-001, but firm load would be interrupted simply
to bring the entity’s ACE back to what it was prior to the loss of the unit. Since the industry has
defined reliability as frequency at or near 60 Hz and transmission lines operating within their
limits, there is no reason to interrupt firm load.
Instead, the BARC SDT is recommending that Standard BAL-002-2 not be enforceable
during an EEA event where the EEA process requires the use of Contingency Reserve to
maintain load service. Instead, the Reliability Coordinator, Transmission Operators and the
impacted Balancing Authorities should use real-time situational awareness, taking into account
issues addressed in BAL-001, BAL-003, the IRO suite of standards and the TOP suite of
standards, to determine what actions are appropriate when conditions are abnormal. This
process would allow continued load service without arbitrarily requiring interruption of firm
load.
This concern arises because the other standards look at specific reliability issues other
than just balancing between scheduled and actual interchange. BAL-001-2 and BAL-003-1 look
at interconnection frequency to determine whether the Balancing Authority is helping or
hurting reliability. During an EEA event, curtailing load to move ACE back to a pre-event level
could adversely affect frequency. If frequency goes up from 60 Hz when a Balancing Authority
interrupts load, the impact is detrimental to the interconnection. Under the TOP standards, if
flows on transmission lines are within the limits specified, there is no need to alter the flows on
the transmission system by interrupting load.
Finally, the Reliability Coordinator has a wide area view of the electric system as
required under the IRO standards. The IRO standards clearly state the Reliability Coordinator’s
responsibilities during the EEA process. If the Reliability Coordinator has not identified a
reliability concern in its near term operations evaluation, actions such as interruption of firm
load should not occur simply to balance load and resources within the BA. During abnormal
(emergency) situations, taking significant actions with a narrow view will not be beneficial for
Interconnection reliability.
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EXAMPLES
o Example 1
On an usually cold day in February 2011, at 06:22, a Balancing Authority Area
(BAA) experienced a 350 MW generation loss when a 750 MW joint ownership
unit tripped off-line. Earlier in the day the BAA operator experienced loss of
several generating units with a total capacity of 1050 MW, the latest loss being
just 38 minutes prior to the 350 MW loss. When the 350 MW event occurred
the BAA operator requested reserve/emergency assistance, shed 300 MW of
customer load to restore contingency reserve, and requested the RC post an
EEA3. The EEA3 was posted. Although the frequency only touched 59.91 Hz,
averaging 59.951 Hz in the first minute of the outage, was it really necessary to
cut load and leave people in the cold, dark of that morning to restore
contingency reserve? Having idle generation, when the Interconnection is
operating reliably, does not warrant shedding customer load.
o Example 2
In June 2012, at 17:08, a BAA experienced an 800 MW generation loss. The BA
and the reserve sharing group (RSG) it participates in were in the process of
replacing the lost generation when, in the thirteenth minute of the recovery
when there were no identified frequency, voltage or loading threats to reliability,
the BAA was directed by its Reliability Coordinator (RC) to shed 120 MW of
customer load. Although the combined Area Control Error (ACE) of the RSG
participants was positive, the RC focused on the ACE of the BAA that lost the
generation – which was still negative – ignoring the fact that the Interconnection
frequency (59.96 Hz) was above the Frequency Trigger Limit (59.932 Hz). The
needless shedding of customer load when system reliability is not threatened
attracted the attention of state regulators who were not happy with the action.
This demonstrates that focusing solely on a BAA’s ACE and not on the true
Interconnection reliability indicators can cause actions that do not support
reliability.
o Example 3
In June 2004, at 0741, a series of events led to a generation loss of over 4,600
MW. In spite of the event size, the Interconnection frequency was arrested
without triggering automatic underfrequency load shedding, thanks to governor
action, frequency sensitive load and deployment of Contingency Reserve (as
required by BAL-002). Some transmission elements exceeded their limits for a
short time (as permitted by the EOP standards), And, prior to the disturbance,
the frequency was in the normal operating range due to automatic generation
control (AGC) operation (as required by BAL-001). During the event almost 1,000
MW of interruptible customer load was shed throughout the interconnected
systems by devices that automatically operated to protect various parts of the
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system (as determined by the TPL and TOP Standards). This demonstrates how
the suite of standards defined by NERC work together to efficiently protect the
system and minimize customer interruptions.
VIII.

CONCLUSIONS

There are important conclusions that can be drawn from this work and the
mathematical guarantees that it provides:
o The Disturbance Control Standard (DCS) as currently configured only looks at
ACE, the imbalance contribution of a single BA, and does not include a specific
frequency error component that indicates the BA’s contribution relative to the
condition of the interconnection to which the BA is connected.
o As the DCS measure does not have a specific frequency component, compliance
to DCS at times conflicts with the overall goal of targeting operation within
predefined Interconnection frequency limits. For example, DCS recovery initiated
from above Scheduled Frequency has a detrimental impact on Interconnection
frequency.
o The focus on ACE alone is insufficient to control frequency on a multiple BA
Interconnection. The correlation of the ACEs among the BAs on the
Interconnection will affect the quality of frequency control independent of how
any individual ACE is controlled.
o Adequate control of Interconnection frequency requires the use of both ACE
(individual BA balancing error) and frequency deviation.
o Adequate control of reliability risk on an Interconnection requires the use of
ACE, frequency deviation and available frequency response.
o BAAL addresses all events impacting Interconnection frequency, both above and
below scheduled frequency.
BAAL addresses all of the above issues in its time domain without requiring response to or
measurement of events that fail to raise reliability concerns. For these reasons, the proposed
applicability of BAL-002 is a reasonable and technically-justified approach that addresses the
seam with EOP-002.

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Table of Contents
Introduction .................................................................................................................................... 3
Rationale by Requirement .............................................................................................................. 8
Requirement 1 ............................................................................................................................ 8
Requirement 2 .......................................................................................................................... 16
Requirement 3 .......................................................................................................................... 18

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Introduction
The revision to NERC Policy Standards in 1996 created a Disturbance Control Standard (DCS). It
replaced B1 [Area Control Error (ACE) must return to zero within 10 minutes following a
disturbance] and B2 (ACE must start to return to zero in 1 minute following a disturbance) with
a standard that states: ACE must return to either zero or a pre-disturbance value of ACE within
15 minutes following a reportable disturbance. Balancing Authorities were required to report
all disturbances equal to or greater than 80% of the Balancing Authority’s Most Severe Single
Contingency (MSSC).
BAL-002 was created to replace portions of Policy 1. It measures the ability of an applicable
entity to recover from a reportable event with the deployment of reserve. The reliable
operation of the interconnected power system requires that adequate capacity and energy be
available to maintain scheduled frequency and avoid loss of firm load following loss of
transmission or generation contingencies. This capacity (Contingency Reserve) is necessary to
replace capacity and energy lost due to forced outages of generation or transmission
equipment. The design of BAL-002 and Policy 1 was predicated on the
Interconnection’sInterconnection operating under normal conditions, and the requirements of
BAL-002 assured recovery from single contingency (N-1) events.
This document provides background on the development and implementation of BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event. This document explains
the rationale and considerations for the requirements and their associated compliance
information. BAL-002-2 was developed to fulfill the NERC Balancing Authority Controls (Project
2007-05) Standard Authorization Request (SAR), which includes the incorporation of the FERC
Order 693 directives. The original SAR, approved by the industry, presumes there is presently
sufficient Contingency Reserve in all the North American Interconnections. The underlying goal
of the SAR was to update the standard to make the measurement process more objective and
to provide information to the Balancing Authority or Reserve Sharing Group, such that the
parties would better understand the use of Contingency Reserve to balance resources and
demand following a Reportable Balancing Contingency Event.
Currently, the existing BAL-002-1 standard contains Requirements specific to a Reserve Sharing
Group which the drafting team believes are commercial in nature and a contractual
arrangement between the reserve sharing group parties. BAL-002-2 is intended to measure the
successful deployment of contingency reserve by responsible entities. Relationships between
the entities should not be part of the performance requirements, but left up to a commercial
transaction.
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Clarity and specifics are provided with several new definitions. Additionally, the BAL-002-2
eliminates any question about who is the applicable entity and assures that the applicable
entity is held responsible for the performance requirement. The drafting team’s goal was to
have BAL-002-2 be solely a performance standard. The primary objective of BAL-002-2 is to
ensure that the applicable entity is prepared to balance resources and demand and to return its
ACE to defined values (subject to applicable limits) following a Reportable Balancing
Contingency Event.
As proposed, this standard is not intended to address events greater than a Responsible Entity’s
Most Severe Single Contingency. These large multi-unit events, although unlikely, do occur.
Many interactions occur during these events and Balancing Authorities (BAs) and Reserve
Sharing Groups must react to these events. However, requiring a recovery of ACE within a
specific time period is much too simple of a methodology to adequately address all of these
interactions. The suite of NERC StandardsStandard work together to ensure that the
Interconnections are operated in a safe and reliable manner. It is not just one standard, rather
it is the combination of the BAL-001-2 standard, (in which R2 requires operation within an ACE
bandwidth based on interconnection frequency), TOP-007, and EOP-002, which collectively
address issues when large events occur.
x

The Balancing Authority ACE Limit (BAAL) in R2 of BAL-001-2 looks at Interconnection
frequency to provide the BA a range in which the BA should strive to operate as well as
a 30-minute period to address instances when the BA is outside of that range. If an
event larger than the BA’s MSSC occurs, the BAAL will likely change to a much tighter
control limit based on the change in interconnection frequency. The 30-minute limit
under the BAAL allows the BA (and its RC) time to quickly evaluate the best course of
action and then react in a reasonable manner. BAAL also ensures the Responsible Entity
balances resources and demand when events occur of less magnitude than a Reportable
Balancing Contingency. In addition R1 of BAL-001-2 requires the BA to respond to
assure Control Performance Standard 1 (CPS1) is met. This may prompt the BA to
respond in some circumstances in less than 10 minutes.

x

The TOP-007 standard addresses transmission line loading. Members of the BAL-002-2
drafting team are aware of instances (typically N-2 or less) that could cause transmission
overloads if certain units were lost and reserves responded.

x

Under EOP-002, if the BA does not believe that it can meet certain parameters, different
rules are implemented.

Because of the potential for significant unintended consequences that could occur under a
requirement to activate all reserves, the drafting team recommends to the industry that the
revised BAL-002-2 only address only events which are planned for (N-1) and not any loss of
resource(s) that would exceed MSSC. Therefore, the definitions and Requirements under BAL002-2 exclude events greater than the MSSC. This provides clarity of Requirements, supports
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reliable operation of the Bulk Electric System and allows other standards to address events of
greater magnitude and complexity.
Within NERC’s State of Reliability Report, ALR2-5 “Disturbance Control Events Greater Than the
Most Severe Single Contingency” has been tracked and reported since 2006. For the period
2006 to 2011 there werehave been 90 disturbance events that exceeded the MSSC, with the
highest in any given year being 24 events. Evaluation of the data illustrates events greater than
MSSC occur very infrequently, and the drafting team believes their exclusion will not have any
adverse impact on reliability.
The metric reports the number of DCS events greater than MSSC, regardless of the size of a
Balancing Authority or RSG and of the number of reporting entities within a Regional Entity. A
small Balancing Authority or RSG may have a relatively small MSSC. As such, a high number of
DCS events greater than MSSC may not indicate a reliability problem for the reporting Regional
Entity, but may indicate an issue for the respective Balancing Authority or RSG. In addition,
events greater than MSSC may not cause a reliability issue for a BA, RSG or Regional Entity that
has more stringent standards which require contingency reserve greater than MSSC.

Background
Reliably balancing an Interconnection requires frequency management and all of its aspects.
Inputs to frequency management include Tie-Line Bias Control, Area Control Error (ACE), and
the various Requirements in NERC Resource and Demand Balancing Standards, specifically BAL001-2 Real Power Balancing Control Performance and BAL-003-1 Frequency Response and
Frequency Bias Setting.
Balancing Contingency Event
BAL-002-2 applies during the real-time operations to ensure the Balancing Authority or Reserve
Sharing Group balance resources and demand by returning its Area Control Error to defined
values following a Reportable Balancing Contingency Event.
The drafting team included a specific definition for a Balancing Contingency Event to eliminate
any confusion and ambiguity. The prior version of BAL-002 was broad and could be interpreted
in various ways leaving the ability to measure compliance in the eye of the beholder. Including
the specific definition allows the Responsible Entity to fully understand how to perform and
meet compliance. Also, FERC Order 693 (at P355) directed entities to include a Requirement
that measures response for any event or contingency that causes a frequency deviation. By
developing a specific definition that depicts the events causing an unexpected change to the
Responsible Entity’s ACE, the necessary response requirements assure the intent of the FERC
requirement is met.
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The definitions of Reportable Balancing Contingency Event and Contingency Event Recovery
Period work together to specify the timing requirements for recoveries from Reportable
Balancing Contingency Events. A Balancing Contingency Event that is not a Reportable
Balancing Contingency Event may impact the compliance requirement for the Reportable
Balancing Contingency Event which occurs after it, because the megawatts lost for both may
exceed the Most Severe Single Contingency. Also, a subsequent Balancing Contingency Event
may occur during the Contingency Event Recovery Period of a Reportable Balancing
Contingency Event, affecting the ACE recovery requirement of the initial event. The drafting
team struggled with associating any specific time window for the megawatt loss to occur within
for an event to qualify as a Balancing Contingency Event. The term sudden implies an
unexpected occurrence in the definition of a Balancing Contingency Event, and the Responsible
Entity should use its best judgment in applying any time criterion to Balancing Contingency
Events that do not qualify as Reportable Balancing Contingency Events.
Most Severe Single Contingency
The Most Severe Single Contingency (MSSC) term has been widely used within the industry;
however, it has never been defined. In order to eliminate a wide range of definitions, the
drafting team has included a specific definition designed to fulfill the needs of the standard. In
addition, in order to meet FERC Order No. 693 (at P356), to develop a continent-wide
contingency reserve policy, it was necessary to establish a definition of MSSC.
When an entity determines its MSSC, the review needs to include the largest loss of resource
that might occur for either generation or transmission loss. If the loss of transmission causes
the loss of generation and load, the size of that event would be the net change. Since the size of
an event where both load and generation are lost due to the loss of the transmission would be
less than just the loss of the generator, this event is unlikely to be the entity’s MSSC. Also, note
here that the drafting team removed the previous requirement to review the MSSC at least
annually. An entity should know what its MSSC is at all times. Therefore, an annual review is no
longer required
Contingency Reserve
Most system operators generally have a good understanding of the need to balance resources
and demand and return their Area Control Error to defined values following a Reportable
Balancing Contingency Event. However, the existing Contingency Reserve definition is focused
primarily on generation and not sufficiently on Demand-Side Management (DSM). In order to
meet FERC Order No. 693 (at P 356) to include a requirement that explicitly allows DSM to be
used as a resource for contingency reserve, the drafting team elected to expand the definition
of Contingency Reserve to explicitly include capacity associated with DSM.
Additionally, conflict existed between BAL-002 and EOP-002 as to when an entity could deploy
or restore its contingency reserve. EOP-002 also applies during the real-time operations time
horizon and addresses capacity and energy emergencies. Given that an entity and/or event can
transition suddenly from normal operations (BAL-002) into emergency operations (EOP-002),
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this transitional seam must be explicitly addressed in order to provide clarity to responsible
entities regarding the actions to be taken.
To eliminate the possible conflict and to assure BAL-002 and EOP-002 work together and
complement each other, the drafting team clarified the existing definition of Contingency
Reserve. The conflict arises since the actions required by Energy Deficient Entities before
declaring either an Energy Emergency Alert 2 or an Energy Emergency Alert 3 include
deployment of all Operating Reserve which includes Contingency Reserve. Conversely, anAn
Energy Deficient Entity may need to declare either an Energy Emergency Alert 2 or an Energy
Emergency Alert 3, before incurring a Balancing Contingency Event. The definition of
Contingency Reserve now allows for deploying capacity to respond to a Balancing Contingency
Event and other contingency requirements such as Energy Emergency Alerts. Readiness to
reduce Firm Demand during the Contingency Reserve Restoration Period during an Energy
Emergency Alert should another Contingency Event occur is proposed for inclusion in the
definition of Contingency Reserve. The Responsible Entity should have processes and
procedures for direct control over the Firm Demand in place for it to be considered Contingency
Reserves prior to the event during an Energy Emergency Alert. without incurring a Balancing
Contingency Event. Without incurring a Balancing Contingency Event, a Responsible Entity
cannot utilize its Contingency Reserve to the extent it drops below MSSC without violating
NERC Standard BAL-002-2. To resolve this conflict, the drafting team elected to allow the
Responsible Entity to be exempt from R2 if in an Energy Emergency Alert Level under which the
Responsible Entity no longer has required Contingency Reserves available provided that the
Responsible Entity has made preparations for interruption of Firm Load to replace the shortfall
of Contingency Reserve to avoid the uncontrolled failure of components or cascading outages
of the Interconnection. Also, to assure the system operator has the necessary flexibility to
address the transition from normal operations (BAL-002) into emergency operations (EOP) the
drafting team elected to allow the Responsible entity to be exempt from R2 during one or more
of the following periods when the Responsible Entity is:
x

using its Contingency Reserve for Contingencies that are not Balancing
Contingency Events;

x

responding to an Operating Instruction requiring the use of Contingency Reserve;

x

resolving the exceedance of a System Operating Limit or IROL that requires the
use of Contingency Reserve; and,

x

in a Contingency Event Recovery Period or its subsequent Contingency Reserve
Restoration Period.

For additional technical justification for exemptionexempting periods from R1R2 to facilitate
transitioning from normal operations into emergency operations please refer to Attachment
23.
Reserve Sharing Group Reporting ACE
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The drafting team elected to include this definition to provide clarity for measurement of
compliance of the appropriate Responsible Entity. Additionally, this definition is necessary
since the drafting team has eliminated R5.1 and R5.2 that are in the existing standard. R5.1 and
R5.2 mix definitions with performance. The drafting team has included all the performance
requirements in the proposed standards R1 and R2, and therefore has added the definition of
Reserve Sharing Group Reporting ACE.
Other Definitions
Other definitions have been added or modified to assure clarification within the standard and
requirements.

Rationale by Requirement
Requirement 1
The Responsible Entity experiencing a Reportable Balancing Contingency Event shall:
1.1. , within the Contingency Event Recovery Period, demonstrate recovery by
returning its Reporting ACE to at least the recovery value of:
x

zeroZero (if its Pre-Reporting Contingency Event ACE Value was positive or
equal to zero); however, during the Contingency Event Recovery Period, any
Balancing Contingency Event that occurs during the Contingency Event
Recovery Period shall reduce the required recovery: (i) beginning at the time
of, and (ii) by the magnitude of, sucheach individual Balancing Contingency
Event,

or,
x

itsIts Pre-Reporting Contingency Event ACE Value, (if its Pre-Reporting
Contingency Event ACE Value was negative);): however, during the
Contingency Event Recovery Period, any Balancing Contingency Event that
occurs during the Contingency Event Recovery Period shall reduce the
required recovery: (i) beginning at the time of, and (ii) by the magnitude of,
sucheach individual Balancing Contingency Event.

1.2. document allAll Reportable Balancing Contingency Events will be documented
using CR Form 1.

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1.3. deploy Contingency Reserve, within system constraints, to respond to all
Reportable Balancing Contingency Events, however, it is 1.2.
A Responsible
Entity is not subject to compliance with Requirement R1 part 1.1 if:
1.3..1 the Responsible Entity is:

1.3

x

when it is experiencing a Reliability Coordinator declaredapproved
Energy Emergency Alert Level, and under which Contingency Reserves
have been activated.

x

utilizing its Contingency Reserve to mitigate an operating emergency in
accordance with its emergency Operating Plan, and

x

the Responsible Entity has depleted its Contingency Reserve to a level
below its Most Severe Single Contingency

or,
Requirement R1 (in its entirety) does not apply:
1.3.2 (i) when the Responsible Entity experiences:
x

multiple Contingencies where the combined MW loss a Balancing
Contingency Event that exceeds its Most Severe Single Contingency
and that are defined as a single Balancing Contingency Event, or , or

x

(ii) after multiple Balancing Contingency Events withinfor which the
sum of the time periods defined by the Contingency Event Recovery
Period and Contingency Reserve Restoration Period whose combined
magnitude exceeds the Responsible Entity'sEntity’s Most Severe
Single Contingency. for those events that occur within that 105
minute period.

Background and Rationale
Requirement R1 reflects the operating principles first established by NERC Policy 1. Its
objective is to assure the Responsible Entity balances resources and demand and returns its
Reportable Area Control Error (ACE) to defined values (subject to applicable limits) following a
Reportable Balancing Contingency Event. It requires the Responsible Entity to recover from
events that would be less than or equal to the Responsible Entity’s MSSC. It establishes the
amount of Contingency Reserve and recovery and restoration timeframes the Responsible
Entity must demonstrate in a compliance evaluation. It is intended to eliminate the ambiguities
and questions associated with the existing standard. In addition, it allows Responsible Entities
to have a clear way to demonstrate compliance and support the Interconnection to the full
extent of its MSSC.
By including new definitions, and modifying existing definitions, and the above R1, the drafting
team believes it has successfully fulfilled the requirements of FERC Order No. 693 (at P 356) to
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include a requirement that explicitly allows DSM to be used as a resource for Contingency
Reserve. It also recognizes that the loss of transmission as well as generation may require the
deployment of Contingency Reserve.
Additionally, R1 is designed to assure the applicable entity uses reserve to cover a Reportable
Balancing Contingency Event or the combination of any previous Balancing Contingency Events
that have occurred within the specified period, to address the Order’s concern that the
applicable entity is responding to events and performance is measured. The Reportable
Balancing Contingency Event definition, along with R1, allows for measurement of
performance. The drafting team has included Attachment 2 illustrating an example of the
calculation for Requirement R1.
In addition, the standard drafting team (SDT) through R1 PartParts 1.2 and 1.3 has clearly
identified when R1 is not applicable. By including R1 Part 1.3.12, the proposed standard
eliminates the existing conflict with the EOP Standards and further addresses the outstanding
interpretation. By clearly stating when R1 is not applicable or does not apply, it eliminates any
auditor interpretation and allows the Responsible Entity to perform the function in a reliable
manner. Requirement R1 does not apply when an entity experiences a Balancing Contingency
Event that exceeds its MSSC (which includes multiple Balancing Contingency Events as
described in R1 part 1.3.2) because aA fundamental goal of the SDT is to assure the Responsible
Entity has enough flexibility to maintain service to load while managing reliability. Also, the
SDT’s intent is to eliminate any potential overlap or conflict with any other NERC Reliability
Standard to eliminate duplicative reporting, and other issues.
The drafting team used data supplied by the Consortium for Electric Reliability Technology
Solutions (CERTS) to help determine all events that have an impact on frequency. Data that
was compiled by CERTS to provide information on measured frequency events is presented in
Attachment 1. Analyzing the data, reveals events of 100 MW or greater would capture all
frequency events for all interconnections. However, at a 100 MW reporting threshold, the
number of events reported would significantly increase with no reliability gain since 100 MW is
more reflective of the outlying events, especially on larger interconnections.
The goal of the drafting team was to design a continent-wide standard to capture the majority
of the events that impact frequency. After reviewing the data and industry comments, the SDT
elected to establish reporting threshold minimums for each respective Interconnection. This
assures the requirements of FERC Order No. 693 are met. The reportable threshold was
selected as the lesser of 80% of the applicable entity’s Most Severe Single Contingency or the
following values for each respective Interconnection:
x
x
x
x

Eastern Interconnection – 900 MW
Western Interconnection – 500 MW
ERCOT – 800 MW
Quebec – 500 MW

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Additionally, the drafting team used only loss of resource events for purposes of determining
the above thresholds.
Violation Severity Levels
In the Violation Severity Levels for Requirement R1, the impact of the Responsible Entity
recovering from a Reportable Balancing Contingency Event depends on the percentage of
desired recovery achieved.
Compliance Calculation
It is important to note that R1 adjusts the required recovery value of Reporting ACE for any
other Balancing Contingency Events that occur during the Contingency Event Recovery Period.
However, to determine compliance score for compliance with R1, the measured contingency
reserve response (instead of the required recovery value of Reporting ACE) is adjusted for any
other Balancing Contingency Events that occur during the Contingency Event Recovery Period.
Both methods of adjustment are mathematically equivalent. Accordingly, the measured
contingency reserve response is computed and compared with the MW lost as follows
(assuming all resource loss values, i.e. Balancing Contingency Events, are positive) to measure
compliance 1:
ͻ

The measured contingency reserve response is equal to one of the following:
o If the Pre-Reportable Contingency Event ACE Value is greater than or equal
to zero, then the measured contingency reserve response equals (a) the
megawatt value of the Reportable Balancing Contingency Event plus (b) the
most positive ACE value within its Contingency Event Recovery Period (and
following the occurrence of the last subsequent event, if any) plus (c) the
sum of the megawatt losses of the subsequent Balancing Contingency Events
occurring within the Contingency Event Recovery Period of the Reportable
Balancing Contingency Event.
o If the Pre-Reportable Contingency Event ACE Value is less than zero, then the
measured contingency reserve response equals (a) the megawatt value of
the Reportable Balancing Contingency Event plus (b) the most positive ACE
value within its Contingency Event Recovery Period (and following the
occurrence of the last subsequent event, if any) plus (c) the sum of the
megawatt losses of subsequent Balancing Contingency Events occurring

1

In adjusting for the adverse impact of rapidly succeeding (i.e. “near”) Events on a Responsible Entity’s Recovery
from an Event, the SDT thought it more prudent to adjust for future near Events rather than for past near Events
because the future Events place an added burden on performance, while adjusting for the past Events instead
lowers the performance requirement. To adjust for both future and past Events amounts to double dealing
because an Event is subsequent to a prior near Event, and both Events would be serving to relieve Recovery from
each other. The SDT allowed only for the extreme case of exempting from recovery prior near Events that
combined exceed MSSC.

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within the Contingency Event Recovery Period of the Reportable Balancing
Contingency Event, minus (d) the Pre-Reportable Contingency Event ACE
Value.
ͻ Compliance is computed as follows on CR Form 1 in order to document all
Balancing Contingency Events used in compliance determination:
ƒ

If the measured contingency reserve response is greater than or
equal to the megawatts lost, then the Reportable Balancing
Contingency Event Compliance equals 100 percent.

ƒ

If the measured contingency reserve response is less than or equal to
zero, then the Reportable Balancing Contingency Event Compliance
equals 0 percent.

ƒ

If the measured contingency reserve response is less than the
megawatts lost but greater than zero, then the Reportable Balancing
Contingency Event Compliance equals 100% * (1 – ((megawatts lost –
measured contingency reserve response) / megawatts lost)).

The above computations can be expressed mathematically in the following 5 sequential steps,
labeled as [1-5], where:
ACE_BEST – most positive ACE during the Contingency Event Recovery Period occurring after
the last subsequent event, if any (MW)
ACE_PRE - Pre-Reportable Contingency Event ACE Value (MW)
COMPLIANCE - Reportable Balancing Contingency Event Compliance percentage (0 - 100%)
MEAS_CR_RESP - measured contingency reserve response for the Reportable Balancing
Contingency Event (MW)
MSSC – Most Severe Single Contingency (MW)
MW_LOST - megawatt loss of the Reportable Balancing Contingency Event (MW)
SUM_SUBSQ - sum of the megawatt losses of subsequent Balancing Contingency Events
occurring within the Contingency Event Recovery Period of the Reportable Balancing
Contingency Event (MW)
If ACE_PRE is greater than or equal to 0, then
MEAS_CR_RESP = MW_LOST +ACE_BEST + SUM_SUBSQ [1]
If ACE_PRE is less than 0, then
MEAS_CR_RESP = MW_LOST +ACE_BEST + SUM_SUBSQ – ACE_PRE [2]
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If MEAS_CR_RESP is greater than or equal to MW_LOST, then
COMPLIANCE = 100 [3]
If MEAS_CR_RESP is less than or equal to 0, then
COMPLIANCE = 0 [4]
If MEAS_CR_RESP is greater than 0, and, MEAS_CR_RESP is less than MW_LOST, then
COMPLIANCE = 100 * (1 – ((MW_LOST – MEAS_CR_RESP)/ MW_LOST)) [5]

The Decision Tree flow diagram for DCS below, provides a visualization of the logic flow for a
Reportable Balancing Contingency Event. It includes decision blocks for initial event
determination, subsequent event determination, and checking for MSSC exceedance which
should assist the Responsible Entity with Event Recovery and analysis.

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BAAL and
IROL

Resource Loss
> Reporting
Threshold

DCS Real
Time

DCS Off
Line
Reporting

N

Sudden?

Y

Start 15
Minute
Recovery
Subsequent
Events?

Y

N

Decision Tree for DCS

Make Best
Efforts on
Recovery

> MSSC

Adjust
Calculations

Y

14

N

If IROL or
BAAL
Exceeded, Begin
30 Min Recover

Complete
Form

Disturbance Control Performance - Contingency Reserve for Recovery From a Balancing Contingency Event Standard Background
Document

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Disturbance Control Performance - Contingency Reserve for Recovery From a Balancing
Contingency Event Standard Background Document

Requirement 2
EachR2. The Responsible Entity shall develop, review and maintain annually, and
implement an Operating Process as part of its Operating Plan to determine its Most
Severe Single Contingency and to have Contingency Reserve equal to, or , averaged
over each Clock Hour, greater than or equal to its average Clock Hour Most Severe
Single Contingency, except during one or more of the following periods when the
Responsible Entity’s Most Severe Single Entity is:
2.1 using its Contingency availableReserve, for maintaining systema
period not to exceed 90 minutes, to mitigate the reliability concerns
associated with Contingencies that are not Balancing Contingency
Events; and/or
2.2 using its Contingency Reserve, for a period not to exceed 90 minutes,
to respond to an Operating Instruction requiring the use of
Contingency Reserve; and/or
2.3 using its Contingency Reserve for a period not to exceed 90 minutes,
to resolve the exceedance of a System Operating Limit (SOL) or
Interconnection Reliability Operation Limit (IROL) that requires the
use of Contingency Reserve; and/or
2.4 in a Contingency Reserve Restoration Period; and/or
2.5 in a Contingency Event Recovery Period; and/or
R2.

in an Energy Emergency Alert Level under which the Responsible Entity no longer
has required Contingency Reserve available provided that the Responsible Entity
has made preparations for interruption of Firm Load to replace the shortfall of
Contingency Reserve to avoid the uncontrolled failure of components or cascading
outages of the Interconnection. For this exemption to apply, the preparations must
be initiated within 5 minutes from the time that the Energy Emergency Alert Level is
declared.

Background and Rationale
R2 establishes a uniform continent-wide contingency reserve policy in the form ofrequirement.
R2 establishes a requirement that a Responsible Entity implement an Operating Plan that
assures Contingency Reservecontingency reserve be at least equal to the applicable entity’s
Most Severe Single Contingency and . By including a definition of Most Severe Single
Contingency. and R2, a consistent uniform continent-wide contingency reserve requirement has
been established. Its goal is to assure that the Responsible Entity will have sufficient
Contingency Reservecontingency reserve that can be deployed to meet R1.
FERC Order 693 (at P356) directed BAL-002 to be developed as a continent-wide contingency
reserve policy. R2 fulfills the requirement associated with the required amount of contingency
reserve a Responsible Entity must have available to respond to a Reportable Balancing
Contingency Event. Within FERC Order 693 (at P336) the Commission noted that the
appropriate mix of operating reserve, spinning reserve and non-spinning reserve should be
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addressed. However, the Order predated the approval of the new BAL-003, which addresses
frequency responsive reserve and the amount of frequency response obligation. With the
development of BAL-003, and the associated reliability performance requirement, the SDT
believes that, with R2 of BAL-002 and the approval of BAL-003, the Commission’s goals of a
continent-wide contingency reserves policy is met. The suites of BAL standards (BAL-001, BAL002, and BAL-003) are all performance-based. With the suite of standards and the specific
requirements within each respective standard, a continent-wide contingency policy is
established.
The Responsible Entity’s Operating Plan will addressIn the process by which Contingency
Reserves greater than or equal to the Most Severe Single Contingency are available in Realtime. Once an entity utilizes its contingency reserve, Violation Severity Levels for Requirement
R3 addresses restorationR1, the impact of the reserves.

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Requirement 3
R3.

Each Responsible Entity, following recovering from a Reportable Balancing
Contingency Event, shall restore depends on the amount of its Contingency Reserve
to at least its Most Severe Single Contingency, before the end of available and
whether it has sufficient response. Additionally, the drafting team understands that
the Responsible Entity’s available Contingency Reserve Restoration Period, but may
vary slightly from MSSC at any Balancing Contingency Event that occurs before the
end of a Contingency Reserve Restoration period resets the beginning of the
Contingency Event Recovery Period.

Background and Rationale
Requirement R3 establishes the restoration of Contingency Reserves following Reportable
Balancing Contingency Events.time. This requirement addresses the need to be prepared for
future Balancing Contingency Events. Contingency Reserves must be restored to at least the
minimum required amount, the Most Severe Single Contingency, to assure that the next event
for which an entity plansvariability is expected to be covered if the event occurs. Contingency
Reserves must be restored within the Contingency Reserve Restoration Period which is defined
as a period not exceeding 90 minutes following the end of the Contingency Event Recovery
Period, which is 15 minutes. recognized in Requirement R2 through averaging the available
Contingency Reserve over each Clock Hour.

The ideal goal of maintaining an amount of Contingency Reserve to cover the Most Severe
Single Contingency at all times is not necessarily in the best interest of reliability. It may have
the unintended result of tying operators' hands by removing use of their available contingency
reserve from their toolbox in order to maintain service to load or manage other reliability
issues. By allowing for the occasional use of this minimal amount of Contingency Reserve at the
operators' discretion for other contingencies, reliability is enhanced. The SDT crafted the
proposed standard to encourage the operators to use, at their discretion and within the limits
set forth in the standard, their available contingency reserve to best serve reliability in Realtime. The last thing that anyone desires is to have Contingency Reserve held available and the
lights go off because the standard would penalize the operator for using the Contingency
Reserve to maintain service to the load. However, the drafting team did not believe that the
use of reserves for issues other than a Reportable Balancing Contingency Event should be
unbounded. The SDT limited the use of Contingency Reserve.
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Attachment 1
NERC Interconnections 2009-2013
Frequency Events Loss MW Statistics

For: NERC BARC Standard Drafting Team
Prepared by: CERTS
Date: October 15, 2013

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Attachment 2
BAL-002-2 R1 Example

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Requirement 1
The Responsible Entity experiencing a Reportable Balancing Contingency Event shall, within
the Contingency Event Recovery Period, demonstrate recovery by returning its
Reporting ACE to at least the recovery value of: [Violation Risk Factor: Medium][Time
Horizon: Real-time Operations]
o

Zero, (if its Pre-Reporting Contingency Event ACE Value was positive or equal
to zero); however, during the Contingency Event Recovery Period, any
Balancing Contingency Event that occurs shall reduce the required recovery:
(i) beginning at the time of, and (ii) by the magnitude of, each individual
Balancing Contingency Event,

Or,
o Its Pre-Reporting Contingency Event ACE Value, (if its Pre-Reporting
Contingency Event ACE Value was negative); however, during the
Contingency Event Recovery Period, any Balancing Contingency Event that
occurs shall reduce the required recovery: (i) beginning at the time of, and (ii)
by the magnitude of, each individual Balancing Contingency Event.
To illustrate the above requirement the following scenario of three Balancing Contingency
Events, and compliance for each event, is provided. It is assumed in this scenario that the
reportable event threshold is 200 MW.

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Event 1 Compliance

x
x
x
x

Responsible Entity Pre-Reporting Contingency Event ACE Value is 100 MW
Time of the Balancing Contingency Event - 12:05
Size of the Balancing Contingency Event - 900 MW
Responsible Entity MSSC - 2,000 MW

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x

Resulting Responsible Entity’s ACE Value following the Balancing Contingency Event
– negative 800 MW

With no additional Contingency Events, the Responsible Entity must demonstrate recovery of
Event 1 by returning its Reporting ACE to at least the recovery value of zero within the
Contingency Event Recovery Period, or by 12:20.
However, if the Responsible Entity experienced another Contingency Event (Event 2) based
upon the following:
x ACE had recovered to negative 350 – prior to Event 2
x Time of the Contingency Event - 12:10
x Size of the Contingency Event - 400 MW
x Responsible Entity Reporting ACE Value at 12:10 – negative 750
At the time of Event 2, the Responsible Entity would reduce the value of its required recovery
from the original Balancing Contingency Event 1 by the size of the Contingency Event at 12:10
(Event 2), thus lowering the required recovery value of ACE to negative 400 MW. The
Responsible Entity would demonstrate recovery from Balancing Contingency Event 1, taking
into account Event 2, by returning its Reporting ACE to at least a negative 400 MW by 12:20.
Now if the Responsible Entity experienced an additional Contingency event (Event 3) prior to
12:20 namely:
x ACE had recovered to negative 550 MW – prior to Event 3
x Time of the Contingency Event - 12:15
x Size of the Contingency Event - 200 MW
x Responsible Entity Reporting ACE Value at 12:15 – negative 750
At the time of Event 3, the Responsible Entity would reduce the value of its required ACE
recovery from the original Balancing Contingency Event 1 by the size of the Contingency Event
at 12:10 (Event 2) and the Contingency Event at 12:15 (Event 3), thus lowering the required ACE
recovery value to negative 600 MW. The Responsible Entity would demonstrate recovery from
Balancing Contingency Event 1, taking into account Events 2 and 3 by returning its Reporting
ACE to at least a negative 600 MW by 12:20.
The Responsible Entity must show compliance for all events that might occur during the
Contingency Event Recovery Period (Event 1). Event 2 and Event 3 from the example above
would demonstrate compliance in a similar fashion as was demonstrated for Event 1 above.
Each would have its own unique Contingency Event Recovery Period as defined by the start of
the respective contingency event (i.e. Event 2’s Contingency Event Recovery Period would begin
at 12:10 and end at 12:25; Event 3’s Contingency Event Recovery Period would begin at 12:15
and end at 12:30). The required ACE Value (0 MW) of recovery from Events 1; the required
ACE Value (-200 MW) of Recovery from Event 2 would be the required Value (0 MW) of
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Recovery from final Event 3) minus the size of Event 3 (200 MW), while the required ACE Value
(-600 MW) of Recovery from Event 1 would be the required Value (0MW) of Recovery from
final Event 3 minus the size (600 MW) of the events 2 (400 MW) & 3 (200 MW) subsequent to
Event 1.

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The following demonstrates the logic used for compliance with Event 2 (from 12:10 – 12:25,
including Event 3).
Event 2 Compliance

Responsible Entity’s required ACE Value of recovery from Event 2 is 0 MW (the same as it was
from the pre-existing initial Contingency Event 1 prior to any adjustment for Event 2)
x Time of the Balancing Contingency Event - 12:10
x Size of the Balancing Contingency Event - 400 MW
x Responsible Entity MSSC - 2,000 MW
x Resulting Responsible Entity’s ACE Value following the Balancing Contingency Event
– negative 750 MW
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With no additional Contingency Events, the Responsible Entity must demonstrate recovery
from Event 2 by returning its Reporting ACE to Event 1’s prior, unadjusted Pre-Reporting
Contingency Event ACE value of 0 MW within the Contingency Event Recovery Period, or by
12:25.
However, the Responsible Entity experienced another Contingency Event (Event 3) based upon
the following:
x
x
x
x

ACE had recovered to negative 550 – prior to Event 3
Time of the Contingency Event - 12:15
Size of the Contingency Event - 200 MW
Responsible Entity Reporting ACE post Contingency Event – negative 750

At the time of Event 3, the Responsible Entity would reduce the value of its required recovery
from the Balancing Contingency Event 2 by the size of Contingency Event 3 at 12:15, thus
lowering the required ACE recovery from Event 2 to negative 200 MW. The Responsible Entity
would demonstrate recovery from both Balancing Contingency Event 1 and Balancing
Contingency Event 2, taking in to account Event 3, by returning its Reporting ACE to at least a
negative 200 MW by 12:30.

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The following demonstrates the logic used for compliance following Event 3 (from 12:15 –
12:30).
Event 3 Compliance

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The Responsible Entity’s required ACE Value of recovery from final Event 3 is 0 MW (the same
as it was from the initial Balancing Contingency Event 1 prior to any subsequent events)
x Time of the Balancing Contingency Event - 12: 15
x Size of the Balancing Contingency Event - 200 MW
x Responsible Entity MSSC - 2,000 MW
Resulting Responsible Entity’s ACE Value following the Balancing Contingency Event
– negative 750 MW
With no additional Contingency Events, the Responsible Entity must demonstrate recovery of
final Event 3 by returning its Reporting ACE to the 0 MW ACE value of 0 MW of recovery from
the initial Event 1 within the Contingency Event Recovery Period, or by 12:30.
The above examples illustrate the minimum response for compliance. Actual events and
recoveries will differ because of matters such as, but not limited to, Contingency Reserve being
deployed differently.

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Attachment 3
Technical Justification for Applicability
of BAL-002 During Emergency Alerts

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Technical Justification for Applicability of BAL-002
During Energy Emergency Alerts
I.

INTRODUCTION

The Balancing Authority Reliability-based Controls standard drafting team (BARC SDT) has
identified a conflict between NERC Reliability Standards BAL-002 and EOP-002 that
unnecessarily requires arbitrary interruption of Firm Load. In order to address this issue, the
BARC SDT is recommending that Standard BAL-002-2 not be enforceable during an Energy
Emergency Alert (EEA) event where the EEA process requires the use of Contingency Reserve to
maintain load service. 2 This document provides support for this recommendation and an
overview of reliable frequency management on the North American Interconnections.
II.

BACKGROUND

Reliably balancing an Interconnection requires frequency management and all of its aspects.
Inputs to frequency management include Tie-Line Bias Control, Area Control Error (ACE), and
the various Requirements in NERC Resource and Demand Balancing Standards, specifically BAL001-2 Real Power Balancing Control Performance and BAL-003-1 Frequency Response and
Frequency Bias Setting.
Reliability Standard BAL-002 applies during the real-time operations time horizon and
addresses the balancing of resources and demand following a disturbance. Reliability Standard
EOP-002 also applies during the real-time operations time horizon and addresses capacity and
energy emergencies. Given that an entity and/or event can transition suddenly from normal
operations into emergency operations (EOP-002) where Contingency Reserve maintained under
BAL-002 may be utilized to serve Firm Load, this transitional seam must be explicitly addressed
in order to provide clarity to responsible entities regarding the actions to be taken. The
proposed applicability of BAL-002 is designed to address this issue.
III.

LEGACY REQUIREMENTS

The Resource and Demand Balancing (BAL) standards include both requirements that have a
sound technical basis and legacy requirements that the industry has used for years but fail to

2

The proposed applicability section states: “Applicability is determined on an individual Reportable Balancing
Contingency Event basis, but the Responsible Entity is not subject to compliance during periods when the
Responsible Entity is in an Energy Emergency Alert Level under which Contingency Reserves have been activated.”

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have a sound technical basis. NERC began replacing these legacy requirements with technically
based requirements starting with the Control Performance Standard1 (CPS1). Both Control
Performance Standard2 (CPS2) and the Disturbance Control Standard (DCS) remain in the
legacy category. The following are specific concerns associated with these requirements.
o When CPS1 was implemented to replace A1/A2, previous requirements were
modified so that CPS1 would apply at all times including the (disturbance)
periods where DCS is applicable, not just during normal operations/periods. So
DCS is not the only standard governing disturbance conditions.
o The Disturbance Control Standard (DCS) and its precursor B1/B2 have been
unique in requiring immediate action by the Balancing Authority (BA), in this
case to address unexpected imbalances within defined limits.
o DCS, albeit results-based in its current form, was initially designed to measure
the utilization of Contingency Reserve to address a loss of resource within the
defined limits. In its results-based form it assumed that implementing sufficient
Contingency Reserves as needed to comply with the recovery requirement
would be a reasonably equitable minimum quantity for all BAs participating in
interconnected operation.
o DCS is based upon ACE recovery to the lower of pre-disturbance ACE or zero. A
Balancing Authority which might be under-generating prior to a generation loss,
could lose a generating unit and under DCS be deemed compliant if it returned
ACE to its pre-disturbance state, though it could still be depressing
Interconnection frequency.
o As DCS recovery from a reportable event must occur within a 15-minute period,
it is possible for a Balancing Authority’s ACE to again go negative after that time,
with a similar impact on Interconnection frequency.
o Since CPS2 allows a BA to be unaccountable for approximately 74 hours of
operation in a 31-day month, an imbalance condition may persist and negatively
impact Interconnection frequency for many hours 3.
o When ACE is modulated by frequency, “significant” losses are defined not only
by the size of the event causing an ACE deviation, but also contingent on the
deviation of Interconnection frequency from Scheduled Frequency.
IV.

3

TIE-LINE BIAS FREQUENCY CONTROL AND ACE

Reliability-Based Control v3, Standard Authorization Request Form, November 7, 2007.

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Tie-Line Bias Frequency Control is implemented on the North American Interconnections
through the use of the ACE Equation. 4 In general, ACE is the term used to determine the loadgeneration imbalance that is being contributed by each Balancing Authority (BA) on an
Interconnection. ACE is a powerful indicator, because it indicates the imbalance within the
boundaries of a single BA, thus defining the Secondary Control responsibilities for that BA and,
therefore, the control action that would return ACE to zero. ACE includes the Frequency Bias
Setting term, which allows the Primary Frequency Control to be a shared service throughout a
multi-BA Interconnection, while assigning to each individual BA the specific responsibilities of
maintaining its own Secondary Frequency Control.
In summary, ACE only provides guidance with respect to Secondary Frequency Control and
does not indicate or provide any direct measure of Primary Frequency Control, and only reflects
the estimated Frequency Response as represented by the Frequency Bias Setting term. NERC
Requirements and supporting documentation for Frequency Response (Primary Frequency
Control) are included in BAL-003-1 Frequency Response and Frequency Bias Setting standard.
More detail on Tie-Line Bias Frequency Control and ACE is attached. 5
V.

CONTROL PERFORMANCE STANDARD1 (CPS1)

Prior to the development of CPS1, the industry assumed that, "It is impossible, however, to
use frequency deviation to identify the specific control area (sic, i.e. BA) with the under- or
over-generation creating the frequency deviation…".3 In the 1990's the development of CPS1
demonstrated that not only was it possible to identify the specific BA creating the frequency
deviation, but that it is also possible not only to determine the relative contribution by each BA
to the magnitude of the frequency deviation 6, but also to determine the relative contribution of
each BA to the reliability risk caused by that deviation. In addition, the CPS1 Requirement
provided a guarantee: "If all BAs on an interconnection complied with the CPS1 Requirement,

4

Illian, Howard F., Understanding ACE, CPS1 and BAAL, Prepared for the NERC BARC Standard Drafting Team,
September 10, 2010 rev. August 19, 2014, Section 2, pp. 1-4, for a derivation of the ACE Equation and the
requirements for implementing it that are included in the definition of ACE appearing in the NERC Glossary.

5

Illian, Howard F., Frequency Control Performance Measurement and Requirements, Ernest
Orlando Lawrence Berkeley National Laboratory, December 2010, for a discussion of the
history of Frequency Control and Performance Measurement.

6

Illian, Howard F., Understanding ACE, CPS1 and BAAL, Section 2, pp. 5-10 for a derivation
of the CPS1 requirement.

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the Root Mean Squared 7 value of the frequency deviation for that Interconnection would be
less than the epsilon1 8 frequency deviation limit for that Interconnection."
CPS1 is a rolling annual average of individual measurements each averaged over oneminute, and is assessed monthly. CPS1 measures the covariance between the ACE of a BA and
the frequency deviation of the Interconnection which is equal to the sum of the ACEs of all of
the BAs. CPS1 has the great value of using the Interconnection frequency to determine the
degree to which ACE among the BAs on a multiple BA Interconnection is harming or helping
interconnection frequency. Since the frequency deviation is a measured value, the ACE of a BA
will directly affect only the CPS1 of the BA with the ACE and not the CPS1 measure of other BAs.
VI.

BALANCING AUTHORITY ACE LIMIT (BAAL)

When the Balancing Resources and Demand (BRD) standard drafting team recognized the
need for a control measure over a shorter time horizon than either CPS1 (annual) or Control
Performance Standard 2 9 (CPS2, monthly) provided, it began looking for a measure that would
allow a window for common imbalance events like a unit trip, while providing a limit on how
much frequency deviation should be allowed over that short period. After considering
numerous alternatives, BAAL was selected as the appropriate short-term measure. 10,11

7

“Root Mean Squared” means the square root of the mean of the squared errors, so that
positive and negative errors do not offset each other and any shift in the mean is counted
as error.

8

“Epsilon1” is the frequency deviation limit determined for each North American
Interconnection and used by CPS1 to bound the Root Mean Squared frequency deviation.
It is 18 mHz on the Eastern, 22.8 mHz on the Western, 30 mHz on the ERCOT, and 21
mHz on the Quebec Interconnections.

9

Proposed to be replaced by BAAL under BAL-001-2, CPS2 requires the BA to move its ACE
within predefined L10 bounds when it is binding (during only 90% of the ten-minute
periods per month) without regard to whether such action helps or hurts Interconnection
frequency.

10

Illian, Howard F., Meeting the Discrete Event Measure (DEM) Objectives with the
Abnormal Operations Measure (AOM), Prepared for the NERC Balancing Resources and
Demand Standard Drafting Team, March 20, 2004.

11

Illian, Howard F., Setting the Balancing Authority ACE Limit (BAAL) for the NERC
Abnormal Operations Measure (AOM), Prepared for the NERC Balancing Resources and
Demand Standard Drafting Team, March 28, 2004.

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Considerable evaluation and Field Trials have shown that BAAL12 is a better indicator of
contributions to reliability risk of an interconnection than the magnitude of ACE alone. This
superiority, like CPS1’s, derives from the concurrent use of both ACE and frequency error in the
BAAL measure. Thus BAAL captures the relative contribution to reliability by all of the ACEs on
an interconnection and indicates where each BA stands relative to its secondary control
responsibilities and the current state of the interconnection as indicated by the frequency error
for both under- and over-frequency conditions.
VII.

INTERACTION BETWEEN STANDARDS

The drafting team has identified as an issue the existence of points where the standards are
in conflict with each other. The drafting team has attempted to address the conflicts identified,
as follows:
NERC standard EOP-002 requires a BA to use all its reserves during an Energy Emergency
Alert 2 (EEA2) or higher. The following language is found in EOP-002 Attachment 1-EOP-002:
2.6.4 Operating Reserves. Operating reserves are being utilized such that the
Energy Deficient Entity is carrying reserves below the required minimum or
has initiated emergency assistance through its operating reserve sharing
program.
The current BAL-002 specifies a minimum level reserve requirement at all times unless a
qualifying event has occurred. The drafting team noted that in the EEA process an entity is
driven to request an EEA rarely as the result of a single unit loss. In fact, an EEA declaration by
the Reliability Coordinator might result from issues that include no event that would qualify as
a Disturbance and the EEA situation could last longer than the reserve recovery period of 90
minutes. For this reason, the drafting team recommends significant changes to the standards in
question.
In addition to the identified conflict, other standards can require the activation of
contingency reserve. These include other BAL standards, IRO standards and TOP standards.
Compared to those standards, the BAL-002 standard provides the least direct measure of
reliability. Therefore, an entity should never be conflicted between applying the requirements
of BAL-002 and complying with the other standards.

12

Illian, Howard F., Understanding ACE, CPS1 and BAAL, Prepared for the NERC BARC
Standard Drafting Team, September 10, 2010 rev. August 19, 2014, Section 2, pp. 10, for
a derivation of the BAAL requirement.

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Finally, there is one overarching principal not reflected in the discussion up to this point,
namely keeping the lights on if possible. If there is a requirement to bring ACE back no matter
what, then that requirement will have the unintended consequence of shedding Firm Load,
especially during an EEA. During the EEA process, the expectation is that a BA will have firm
load ready to shed in order to meet its reserve requirement under R2 of the proposed BAL-002
standard. However, if the BAL-002 standard also requires the entity to meet R1 during the EEA,
entities will shed firm load to restore ACE to its pre-contingency level, regardless of the lack of
any reliability issues. In other words, frequency could be settling at or very near 60 Hz, no
transmission lines are overloaded as determined by the TOP standards, and the entity is
operating within the parameters defined in BAL-001, but firm load would be interrupted simply
to bring the entity’s ACE back to what it was prior to the loss of the unit. Since the industry has
defined reliability as frequency at or near 60 Hz and transmission lines operating within their
limits, there is no reason to interrupt firm load.
Instead, the BARC SDT is recommending that Standard BAL-002-2 not be enforceable
during an EEA event where the EEA process requires the use of Contingency Reserve to
maintain load service. Instead, the Reliability Coordinator, Transmission Operators and the
impacted Balancing Authorities should use real-time situational awareness, taking into account
issues addressed in BAL-001, BAL-003, the IRO suite of standards and the TOP suite of
standards, to determine what actions are appropriate when conditions are abnormal. This
process would allow continued load service without arbitrarily requiring interruption of firm
load.
This concern arises because the other standards look at specific reliability issues other
than just balancing between scheduled and actual interchange. BAL-001-2 and BAL-003-1 look
at interconnection frequency to determine whether the Balancing Authority is helping or
hurting reliability. During an EEA event, curtailing load to move ACE back to a pre-event level
could adversely affect frequency. If frequency goes up from 60 Hz when a Balancing Authority
interrupts load, the impact is detrimental to the interconnection. Under the TOP standards, if
flows on transmission lines are within the limits specified, there is no need to alter the flows on
the transmission system by interrupting load.
Finally, the Reliability Coordinator has a wide area view of the electric system as
required under the IRO standards. The IRO standards clearly state the Reliability Coordinator’s
responsibilities during the EEA process. If the Reliability Coordinator has not identified a
reliability concern in its near term operations evaluation, actions such as interruption of firm
load should not occur simply to balance load and resources within the BA. During abnormal
(emergency) situations, taking significant actions with a narrow view will not be beneficial for
Interconnection reliability.
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EXAMPLES
o Example 1
On an usually cold day in February 2011, at 06:22, a Balancing Authority Area
(BAA) experienced a 350 MW generation loss when a 750 MW joint ownership
unit tripped off-line. Earlier in the day the BAA operator experienced loss of
several generating units with a total capacity of 1050 MW, the latest loss being
just 38 minutes prior to the 350 MW loss. When the 350 MW event occurred
the BAA operator requested reserve/emergency assistance, shed 300 MW of
customer load to restore contingency reserve, and requested the RC post an
EEA3. The EEA3 was posted. Although the frequency only touched 59.91 Hz,
averaging 59.951 Hz in the first minute of the outage, was it really necessary to
cut load and leave people in the cold, dark of that morning to restore
contingency reserve? Having idle generation, when the Interconnection is
operating reliably, does not warrant shedding customer load.
o Example 2
In June 2012, at 17:08, a BAA experienced an 800 MW generation loss. The BA
and the reserve sharing group (RSG) it participates in were in the process of
replacing the lost generation when, in the thirteenth minute of the recovery
when there were no identified frequency, voltage or loading threats to reliability,
the BAA was directed by its Reliability Coordinator (RC) to shed 120 MW of
customer load. Although the combined Area Control Error (ACE) of the RSG
participants was positive, the RC focused on the ACE of the BAA that lost the
generation – which was still negative – ignoring the fact that the Interconnection
frequency (59.96 Hz) was above the Frequency Trigger Limit (59.932 Hz). The
needless shedding of customer load when system reliability is not threatened
attracted the attention of state regulators who were not happy with the action.
This demonstrates that focusing solely on a BAA’s ACE and not on the true
Interconnection reliability indicators can cause actions that do not support
reliability.
o Example 3
In June 2004, at 0741, a series of events led to a generation loss of over 4,600
MW. In spite of the event size, the Interconnection frequency was arrested
without triggering automatic underfrequency load shedding, thanks to governor
action, frequency sensitive load and deployment of Contingency Reserve (as
required by BAL-002). Some transmission elements exceeded their limits for a
short time (as permitted by the EOP standards), And, prior to the disturbance,
the frequency was in the normal operating range due to automatic generation
control (AGC) operation (as required by BAL-001). During the event almost 1,000
MW of interruptible customer load was shed throughout the interconnected
systems by devices that automatically operated to protect various parts of the
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system (as determined by the TPL and TOP Standards). This demonstrates how
the suite of standards defined by NERC work together to efficiently protect the
system and minimize customer interruptions.
VIII.

CONCLUSIONS

There are important conclusions that can be drawn from this work and the
mathematical guarantees that it provides:
o The Disturbance Control Standard (DCS) as currently configured only looks at
ACE, the imbalance contribution of a single BA, and does not include a specific
frequency error component that indicates the BA’s contribution relative to the
condition of the interconnection to which the BA is connected.
o As the DCS measure does not have a specific frequency component, compliance
to DCS at times conflicts with the overall goal of targeting operation within
predefined Interconnection frequency limits. For example, DCS recovery initiated
from above Scheduled Frequency has a detrimental impact on Interconnection
frequency.
o The focus on ACE alone is insufficient to control frequency on a multiple BA
Interconnection. The correlation of the ACEs among the BAs on the
Interconnection will affect the quality of frequency control independent of how
any individual ACE is controlled.
o Adequate control of Interconnection frequency requires the use of both ACE
(individual BA balancing error) and frequency deviation.
o Adequate control of reliability risk on an Interconnection requires the use of
ACE, frequency deviation and available frequency response.
o BAAL addresses all events impacting Interconnection frequency, both above and
below scheduled frequency.
BAAL addresses all of the above issues in its time domain without requiring response to or
measurement of events that fail to raise reliability concerns. For these reasons, the proposed
applicability of BAL-002 is a reasonable and technically-justified approach that addresses the
seam with EOP-002.

BAL-002-2 - Background Document
JulyJanuary 2015

41

BAL-002-0 R4

BAL-002-0 R3

BAL-002-0 R2

BAL-002-0 R1

Requirement in
Approved Standard

Standard: BAL-002-0 – Disturbance Control Standard
Transitions to the below Requirement in
Description and Change Justification
New Standard or Other Action
This Requirement has been moved into BALThis requirement does not provide for a reliability outcome and if
002-2 Applicability and “Additional
violated would not cause separation, instability or cascading outages.
Compliance Information” sections
This requirement falls under the Paragraph 81 rules. This requirement
This requirement has been removed from
defines a commercial agreement between the BA involved in the RSG.
BAL-002-2
This requirement does not provide for a reliability outcome and if
violated would not cause separation, instability or cascading outages.
This requirement was broken apart. The requirement was defining two
Requirement R1 and R2
separate actions; 1) to require activation of Contingency Reserves, and
2) to require having Contingency Reserves equal to its MSSC.
Requirement R1 mandates recovery from a Reportable Balancing
This Requirement has been moved into BAL- Contingency Event.
002-2 Requirement R1 and into the
“Contingency Event Recovery Period”
A portion of this requirement was defining the timing for recovery from
definition.
an event. This has now been defined and has been proposed to be
added to the NERC Glossary of Terms.

Transition of BAL-002-0 to BAL-002-2

Project 2010-14.1 Mapping Document

BAL-002-0 R6

BAL-002-0 R5

Requirement in
Approved Standard

This Requirement has been moved into the
BAL-002-2 Requirement R3 and
“Contingency Event Restoration Period”
definition.

2

A portion of this requirement was defining the timing for restoration of
Contingency Reserve after an event. This has now been defined and
has been proposed to be added to the NERC Glossary of Terms.

Requirement R3 mandates restoration of Contingency Reserve
following a Balancing Contingency Event.

Standard: BAL-002-0 – Disturbance Control Standard
Transitions to the below Requirement in
Description and Change Justification
New Standard or Other Action
This Requirement has been moved into BALA portion of this requirement was defining how a RSG calculates its
002-2 Requirement R1 and “Reserve Sharing
ACE. This has now been defined and has been proposed to be added
Group Reporting ACE” definition.
to the NERC Glossary of Terms.

BAL-002-0 R4

BAL-002-0 R3

BAL-002-0 R2

BAL-002-0 R1

Requirement in
Approved Standard

Standard: BAL-002-0 – Disturbance Control Standard
Transitions to the below Requirement in
Description and Change Justification
New Standard or Other Action
This Requirement has been moved into BALThis requirement does not provide for a reliability outcome and if
002-2 Applicability and “Additional
violated would not cause separation, instability or cascading outages.
Compliance Information” sections
This requirement falls under the Paragraph 81 rules. This requirement
This requirement has been removed from
defines a commercial agreement between the BA involved in the RSG.
BAL-002-2
This requirement does not provide for a reliability outcome and if
violated would not cause separation, instability or cascading outages.
This requirement was broken apart. The requirement was defining two
Requirement R1 and R2
separate actions; 1) to require activation of Contingency Reserves, and
2) to require having Contingency Reserves equal to its MSSC.
Requirement R1 mandates recovery from a Reportable Balancing
This Requirement has been moved into BALContingency Event.
002-2 Requirement R1 and into the
“Contingency Event Recovery Period” and
A portion of this requirement was defining the timing for recovery from
“Contingency Reserve Restoration Period”
an event. This has now been defined and has been proposed to be
definitions.definition.
added to the NERC Glossary of Terms.

Transition of BAL-002-0 to BAL-002-2

Project 2010-14.1 Mapping Document

BAL-002-0 R6

BAL-002-0 R5

Requirement in
Approved Standard

This Requirement has been moved into the
BAL-002-2 Requirement R1R3 and
“Contingency Event Restoration Period”
definition.

2

A portion of this requirement was defining the timing for recovery
fromrestoration of Contingency Reserve after an event. This has now
been defined and has been proposed to be added to the NERC Glossary
of Terms.

Requirement R3 mandates restoration of Contingency Reserve
following a Balancing Contingency Event.

Standard: BAL-002-0 – Disturbance Control Standard
Transitions to the below Requirement in
Description and Change Justification
New Standard or Other Action
This Requirement has been moved into BALA portion of this requirement was defining how a RSG calculates its
002-2 Requirement R1 and “Reserve Sharing
ACE. This has now been defined and has been proposed to be added
Group Reporting ACE” definition.
to the NERC Glossary of Terms.

Standards Announcement

Project 2010-14.1 Phase 1 of Balancing Authority
Reliability-based Controls: Reserves
BAL-002-2
Formal Comment Period Open through August 20, 2015
Ballot Pools Forming through August 5, 2015
Now Available

A 45-day formal comment period for BAL-002-2 – Contingency Reserve for Recovery from Balancing
Contingency Event is open through 8 p.m. Eastern, Thursday, August 20, 2015.
Commenting

Use the electronic form to submit comments on the standard. 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, Wednesday, August 5, 2015.
Since the ballot pools for this project are outdated, new ones are being formed in the Standards
Balloting & Commenting System (SBS). If you previously joined the ballot pools for BAL-002-2, you
must join these ballot pools to cast a vote. Previous BAL-002-2 ballot pool members will not be
carried over. Registered Ballot Body members in the SBS may join the ballot pools here.
Next Steps

An additional ballot for the standard and a non-binding poll of the associated Violation Risk Factors
and Violation Severity Levels will be conducted August 11-20, 2015.
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

8/20/2015

End Date

Responses By Question

1. Please provide any issues you have on this draft of the BAL-002-2 standard and offer a
proposed solution for those issues.

Survey Questions

2010-14.1 Phase 1 of Balancing Authority Reliability-based Controls BAL-002-2 IN 1 ST

Associated Ballots

7/7/2015

2010-14.1 Phase 1 of Balancing Authority Reliability-based Controls | BAL-002-2

Start Date

Description

Name

Survey Details

Survey Report

1. Please provide any issues you have on this draft of the BAL-002-2 standard and offer a
proposed solution for those issues.

0

Dislikes:

0
0

Dislikes:

Our entity, as a Generation only BA, currently under BAL-002-1 uses
“Coordinated adjustments to interchange schedules” as the primary method of
meeting the standard. The new standard BAL-002-2 Rev 7 is not clear if
“Coordinated adjustments to interchange schedules” will be allowed. We feel the
language needs to be clarified as to what is allowed as contingency reserve since
“The provision of capacity that may be deployed by Balancing Authority” is vague.

Likes:

Document Name:

Answer Comment:

Selected Answer:

Dan Roethemeyer - Dynegy Inc. - 5 -

0

Our entity, as a Generation only BA, currently under BAL-002-1 uses
“Coordinated adjustments to interchange schedules” as the primary method of
meeting the standard. The new standard BAL-002-2 Rev 7 is not clear if
“Coordinated adjustments to interchange schedules” will be allowed. We feel the
language needs to be clarified as to what is allowed as contingency reserve since
“The provision of capacity that may be deployed by Balancing Authority” is vague.

Likes:

Document Name:

Answer Comment:

Selected Answer:

Dan Roethemeyer - Dynegy Inc. - 5 -

0
0

Likes:

Dislikes:

0
0

Dislikes:

-----

Likes:

Document Name:

Answer Comment:

Selected Answer:

Alex Ybarra - Public Utility District No. 2 of Grant County, Washington - 5 -

Project_2010-14_1_BAL-002-2_Unofficial_Comment_Form_07072015.docx

EEI, as a Generation only BA, currently under BAL-002-1 uses “Coordinated
adjustments to interchange schedules” as the primary method of meeting the
standard. The new standard BAL-002-2 Rev 7 is not clear if “Coordinated
adjustments to interchange schedules” will be allowed. We feel the language
needs to be clarified as to what is allowed as contingency reserve since “The
provision of capacity that may be deployed by Balancing Authority” is vague.

Document Name:

Answer Comment:

Selected Answer:

Dan Roethemeyer - Dynegy Inc. - 5 -

0

Dislikes:

0

Dislikes:

0
0

Dislikes:

none

Likes:

Document Name:

Answer Comment:

Selected Answer:

John Fontenot - Bryan Texas Utilities - 1 -

0

x

Likes:

Document Name:

Answer Comment:

Selected Answer:

John Shaver - Southwest Transmission Cooperative, Inc. - 1 -

0

No Comment just want to vote Yes

Likes:

Document Name:

Answer Comment:

Selected Answer:

Alex Ybarra - Public Utility District No. 2 of Grant County, Washington - 5 -

0

Dislikes:

0

Dislikes:

0
0

Dislikes:

none

Likes:

Document Name:

Answer Comment:

Selected Answer:

John Fontenot - Bryan Texas Utilities - 1 -

0

none

Likes:

Document Name:

Answer Comment:

Selected Answer:

John Fontenot - Bryan Texas Utilities - 1 -

0

No issues

Likes:

Document Name:

Answer Comment:

Selected Answer:

Nick Vtyurin - Manitoba Hydro - 1,3,5,6 - MRO

Xcel Energy
American Transmission Company MRO
Otter Tail Power Company
Minnkota Power Cooperative, Inc MRO
Basin Electric Power Cooperative MRO
Lincoln Electric System
Western Area Power
Administration
Alliant Energy
Omaha Public Utility District
Midwest ISO Inc.
Great River Energy
Minnesota Power
Rochester Public Utilities
MidAmerican Energy Company
Wisconsin Public Service
Corporation
Nebraska Public Power District

Amy Casucelli

Chuck Lawrence

Chuck Wicklund

Theresa Allard

Dave Rudolph

Kayleigh Wilkerson

Jodi Jenson

Larry Heckert

Mahmood Safi

Marie Knox

Mike Brytowski

Randi Nyholm

Scott Nickels

Terry Harbour

Tom Breene

Tony Eddleman

1,2,3,4,5,6
Region(s)
MRO

Emily Rousseau

Entity

MRO

Selected Answer:

Segment

MRO

MRO

MRO

MRO

MRO

MRO

MRO

MRO

MRO

MRO

MRO

MRO

Voter

Voter Information

MRO

Madison Gas & Electric

Joe Depoorter
MRO

Region

MRO-NERC Standards Review Forum (NSRF)

Group Member Name Entity

Group Name:

Group Information

Emily Rousseau - MRO - 1,2,3,4,5,6 - 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

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

Segments

Answer Comment:

For the definition of Contingency Event Recovery Period, since small events can
happen in sequence (such as runbacks or individual generator trips on a
combined cycle plant), the recovery period should not start with the initial decline
as the BA may not know they are in a DCS event until the event has played
out. Recommend changing the wording be changed to "begins at the time when
ACE reaches the reportable threshold of a Balancing Contingency Event, and
extends for fifteen minutes”

Most Severe Single Contingency (MSSC): The Balancing Contingency Event,
due to a single contingency as identified and maintained in the system models
within the Reserve Sharing Group (RSG) or a Balancing Authority’s area that is
not part of a Reserve Sharing Group, that would result in the greatest loss
(measured in MW) of resource output used by the RSG or a Balancing Authority.

The last two and a half lines of the MSSC definition are unnecessary. The
definition can be:

Under the term for a Balancing Contingency Event, a change in ACE is only
mentioned for the loss of generation, not the other resource losses. It’s probably
not necessary to mention change in ACE as a resource loss is a resource loss.

While not primary concerns, the standard could be clearer if the following
changes were made:

The standard should retain a simple quarterly report form rather than creating
forms for each report. The reasoning the drafting team gave for not adopting this
recommendation is not substantiated. It just says that VSLs for small entities will
be Severe without providing examples. Performance is performance. Size has no
impact in this standard. VSLs are just a starting point in the enforcement
process. Regional enforcement staff will determine the seriousness and risk
associated with a violation. We can provide a simple example of a form that
would work for this standard. It would keep reporting simple and provide NERC
the data it needs for its State of Reliability Report.

R1.1.2, reporting events should be covered in the compliance section of the
standard, not a requirement. Please refer to NERC’s paragraph 81 criteria “B4
Reporting”, which notes that documentation should not be included in a standard
as a requirement.

Our primary concerns are the following:

We appreciate that the drafting team has removed the zero defect component of
the standard and that the current draft acknowledges that reserves should be
deployed to address multiple reliability issues.

0
0

Likes:

Dislikes:

Document Name:

We can provide a redline of the standard that has minor housekeeping edits that
would simplify wording upon request.

0

Dislikes:

0

Dislikes:

Answer Comment:

Selected Answer:

x

R2 is ambiguous as to what is meant by “review and maintain annually,
and implement”. While it looked like the drafting team moved away from
a zero defect standard (where reserves must be > MSSC every hour), the
RSAW implies that the ERO interprets this wording differently. The
drafting team’s intent should be clear in the measure that operators
should not be discouraged to deploy reserves when needed, but they do

We have three primary concerns with this standard:

Terry BIlke - Midcontinent ISO, Inc. - 2 -

0

As a stakeholder of MISO, we are supporting their comments.

Likes:

Document Name:

Answer Comment:

Selected Answer:

Joe O'Brien - NiSource - Northern Indiana Public Service Co. - 6 -

0

MRO supports the intent of BAL-002-2 however, MRO does not support the
addition of R1.2. R1.2 is purely adminstrative in nature and reporting should not
be part of a reliability Standard.

Likes:

Document Name:

Answer Comment:

Selected Answer:

Russel Mountjoy - Midwest Reliability Organization - 10 -

0
0

Likes:

Dislikes:

Document Name:

We do not agree with the move away from simple quarterly
reporting. While there is stray wording in Order No. 693 on compliance
for single events, this does not preclude submitting a quarterly report. As
it is, NERC will likely still request this data for “State of Reliability
Reporting” and then auditors will ask to see the reports again as well.

x

We had additional comments that would make the standard simpler or
clearer. These have been previously sent to the drafting team.

As the current standard is structured, it looks like it will cause BAs to request
EEAs whenever reserves are reduced to address day to day balancing
issues. Even though there is no change in reliability, the likely step
increase in EEAs will likely trigger other concerns, the solution for which
would likely be another standard. The standard should be clearer in the
measure and supporting information that reserves can be drawn down,
but the BA needs an approach to replenish them or call EEAs if unable to
do so.

The Paragraph 81 criteria note that reporting and filling out paperwork
should not be a requirement, yet there is such a requirement to
“document all Reportable Balancing Contingency Events using CR Form
1”. Rather than a requirement, this should be explained in the
compliance section of the standard.

x

need an approach to be notified when reserves are low and a means to
replenish them.

0

Dislikes:

Answer Comment:

Selected Answer:

As an illustration, failing R1 except under certain conditions which include
the Contingency Reserve Restoration period implies that a BA didn’t have
sufficient contingency reserve to meet the ACE recovery requirement
stipulated in R1. Failing R3 means a BA did not restore (or have) sufficient
contingency reserve except during the Contingency Reserve Restoration
period. Note that an event may or may not occur at a time when a BA does
not have sufficient CR, so a BA may fail R3 alone but not R1. However, the
reverse is not true. A BA that fails R1 will most likely (if not invariably) also
fails R3, hence the double jeopardy.

However, we are still unable to find the need and reliability benefit of R3
which requires a BA to restore its Contingency Reserve to at least its Most
Severe Single Contingency (MSSC) before the end of the Contingency
Reserve Restoration Period given the need to meet R1 except under the
specified conditions which include events occurring during Contingency
Reserve Restoration Period. By virtue of meeting R1, a BA must have
Contingency Reserve that equals or exceeds MSSC at all time (expect under
the conditions in Part 1.3). Replenishing Contingency Reserve is thus an
implicit requirement in R1. Having an explicit requirement for replenishing
reserve in R3 will expose Responsible Entities to potential double jeopardy,
is unnecessary and adds no reliability value.

The IESO thanks the SDT for revising the previous R2 to remove those
parts that contain confusing language and are deemed unnecessary.

Leonard Kula - Independent Electricity System Operator - 2 -

0

Hydro-Quebec TransEnergie supports NPCC comments.

Likes:

Document Name:

Answer Comment:

Selected Answer:

Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 - NPCC

0

Dislikes:

Answer Comment:

Selected Answer:

Also, we feel the same R1.1 waiver should apply for multiple contingencies that
use all of the required reserve regardless of whether a declared Energy
Emergency Alert is in effect. An EEA is used only if there are already insufficient
reserves to meet requirements or an expectation of not meeting requirements. In
the case of a non-emergency normal restoration that doesn't require a declared
emercy but becomes difficult near the end of the Contingency Event Recovery
Period, the time it takes to declare an emergency may extend the actual recovery
beyond the Contingency Event Recovery Period thereby creating a noncompliance. The exemption in the current BAL-002-1 standard (see section 1.5 of
part D of the standard) does not require a previously declared emergency. If
necessary, a declaration of an Energy Emergency Alert can be made ASAP
after a restoration has failed to meet the Contingency Event Recovery
Period requirement.

We also submitted our comments through NPCC. We feel the intent of the 3rd
bullet of Requirement 1.3.1 is to ensure that all required reserve up to the MSSC
required reserve value is used prior to the waiver of Requirement 1.1 becoming
available. The current wording suggests that you need only deplete reserves to a
value less than the MSSC required reserve amount and the waiver will be
enabled. This would wave the normal requirement to restore ACE
even while leftover reserve is still available. We feel the wording "the Responsible
Entity has depleted its Contingency Reserve to a level below its Most Severe
Single Contingency" should be changed to read "the Responsible Entity has
depleted its Contingency Reserve by at least the amount of reserve required for
its Most Severe Single Contingency".

Rob Vance - NB Power Corporation - 5 -

0

Likes:

Document Name:

We therefore once again propose that R3 be removed.

Having only R1 would suffice as this requirement will drive a BA to recover
or have sufficient CR except under certain conditions.

0

Dislikes:

Likes:

Document Name:

Answer Comment:

Selected Answer:

0

3. Requirement R3 seems to contain obligations that are related to/repeated
from R1. The obligation to restore Contingency Reserve should be
merged into R1.

2. Sub-Requirement R1.2 refers to documentation and as such is
administrative in nature, i.e. does not contribute to
Reliability. Furthermore, it seems to meet Criterion B4 of the Paragraph
81 Criteria.

1. R1.3 is confusing. Instead of detailing what the Responsible Entity must
do, it extends to details on what is NOT subject to compliance. Results
based standards must focus on what reliability objectives are to be
achieved rather than what is not subject to compliance. All after
“however, it is not subject to compliance with Requirement 1, part 1.1….”
does not belong in the requirement. It could be part of the Compliance
Section.

The SDT should be commended for its work in putting forward this
draft. However, there are a number of areas where the draft can be improved
before adoption by NERC.

David Kiguel - David Kiguel - 8 -

0

Likes:

Document Name:

0

0
0

Dislikes:

R2. If we understand correctly, this requirement is extending the requirement of
EOP-011-1 R2 by reference. We do not believe it is advisable to include a
requirement that adds to the elements of another requirement in a separate
standard. It raises tangential questions such as “does this Operating Process
have to be RC-approved as the Operating Plan does?”

R1.3. AZPS is concerned that the NERC Glossary of Terms only allows a BA or
LSE to be in an EEA. And EOP-002-3.1 R7 and R8 have the Balancing Authority
requesting to be declared in an EEA. If a Balancing Authority were in an RSG,
that would make the RSG the Responsible Entity under BAL-002-2. If the BA
was experiencing and requested an EEA, does this transfer exception allowed in
R1.3 to the RSG as not being subject to compliance?

R1.2. should not be included in the requirements section. This administrative
function would violate FERC P81 as administrative in nature. Also, the process
or form could change.

Likes:

Document Name:

Answer Comment:

Selected Answer:

Jeri Freimuth - APS - Arizona Public Service Co. - 3 -

Dislikes:

0

Dislikes:

Answer Comment:

Selected Answer:
1. The High VSL for R2 in the proposed BAL-002-2, as well as auditor
guidance in the proposed BAL-002-2 RSAW, could be interpreted to
require Contingency Reserve to be > MSSC at all times other than when
deployed in response to a Balancing Contingency Event. However, in the
Western Interconnection BAL-002-WECC-2 allows clock-hour averaging
to determine if Contingency Reserves were adequately maintained. How
will this apparent conflicting methodology be reconciled if BAL-002-2 is
passed?
2. The definition of Contingency Reserve in the proposed BAL-0022 indicates this is capacity that may be deployed to respond to a
Balancing Contingency Event. However, R3 states “Each Responsible
Entity, following a Reportable Balancing Contingency Event, shall
restore Contingency Reserve to at least its Most Severe Single
Contingency before the end of the Contingency Reserve Restoration
Period...". The proposed standard does not identify how long an entity
has to return Contingency Reserve following deployment for a Balancing
Contingency Event (i.e. - not "Reportable").

Richard Vine - California ISO - 2 -

0

The recovery value for any Balancing Contingency Event(s) that occurs
during the Contingency Event Recovery Period shall be the recovery value
for the initial event.

BPA is in agreement with the proposed standard. However, BPA believes there
should be a clarifying comment in requirement R1. In R1, sub-requirement 1.1,
following the second bullet, BPA would like the standard to state:

Likes:

Document Name:

Answer Comment:

Selected Answer:

Andrea Jessup - Bonneville Power Administration - 1,3,5,6 - WECC

0

Dislikes:

Answer Comment:

Selected Answer:

Under the Rationale for Requirement R1 on page 7, the phrase
4.
“..returns its Area Control Error (ACE) to defined values…” should include a

3.
Under the Contingency Reserve Restoration Period definition on page
4, the period should be 30 minutes instead of 90 minutes in order to be
consistent with the NERC TOP-004 (Transmission Operations) Standard.

2.
Using arbitrary MW definitions for each major Interconnection (on page 4)
under the same section on the definition of a Reportable Balancing
Contingency Event, may lead to inconsistent results, as the MW values actually
needed are dynamic and based on the amount of load and on-line generation at
the time of the disturbance or contingency event.

A specific percent change in ACE (Area Control Error) needs to be
1.
specified in the definition of Reportable Balancing Contingency Event, where it
states “…sudden decline in ACE based on EMS scan rate…” (on page 3).

I am recommending a NO vote for the following reasons:

Spencer Tacke - Modesto Irrigation District - 4 -

0

Likes:

Document Name:

0

Dislikes:

Answer Comment:

Selected Answer:

1. Requirement R1, Part 1.3.1

ReliabilityFirst votes in the Affirmative because the standard helps to better
ensure the Balancing Authority or Reserve Sharing Group balances
resources and demand and returns the Balancing Authority's or Reserve
Sharing Group's Area Control Error to defined values (subject to applicable
limits) following a Reportable Balancing Contingency Event. ReliabilityFirst
offers the following comments for consideration:

Anthony Jablonski - ReliabilityFirst - 10 -

0

Likes:

Document Name:

209-526-7414

Modesto Irrigation District

Senior Electrical Engineer

Spencer Tacke

Sincerely,

Thank you.

locational reference to the actual defined values (i.e., what are they and where
can they be found ?).

0

Dislikes:

Answer Comment:

Selected Answer:

The BAL-002-2 RSAW posted further supports our primary concern “Review the
evidence and verify that the entity had available Contingency reserves equal to,
or greater than its Most Severe Single Contingency” Suggest the wording be

R2 M2 Contingency Reserves can and should be deployed for reasons to include
loss of resources temporarily till mitigation measures are implemented less than
MSSC. M2 does not make it clear that reserves can be used for any other
resource loss less than MSSC. It appears you have to provide data that you had
reserves >= MSSC each hour.

R 1.1.2 Reporting should not be a requirement.

Edward Magic - SCANA - South Carolina Electric and Gas Co. - 5 -

0

• has depleted its Contingency Reserve to a level below its Most Severe
Single Contingency

• [is] utilizing its Contingency Reserve to mitigate an operating emergency in
accordance with its emergency Operating Plan, and

• [is] experiencing a Reliability Coordinator declared Energy Emergency Alert
Level, and

Likes:

Document Name:

There is a disconnect between the lead in Part 1.3.1 and the third
bullet. The lead in states “the Responsible Entity is:” and the
third bullet states “the Responsible Entity has depleted…”. As
one can see, there is a double use of the term “the Responsible
Entity”. RF recommends the following language for
consideration:

1.3.1 the Responsible Entity:

i.

0
0

Likes:

Dislikes:

Document Name:

revised “Confirm the applicable Entity met the Contingency Requirement for
Reportable Balancing Contingency Event(s)”

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,RFC

Entity

LG&E and KU Energy LLC

Answer Comment:

6

5

1

3

Segments

The proposed draft 7 requires reporting and compliance evaluation of each
individual Reportable BCE. Quarterly reporting and evaluation of Reportable
Events on a quarterly basis has worked well and should be continued.

4.1.1.1. A Balancing Authority that is not a member of a NERC registered
Reserve Sharing Group is the Responsible Entity.

Suggested solution – Modify language in 4.1.1.1 to:

Clarity is needed as to whether or if a BA that is a member of an RSG but does
not request RSG assistance for a specific BCE is considered the Responsible
Entity. The “active status” language used in 4.1.1.1 is unclear.

Comments

These comments are submitted on behalf of the following PPL NERC Registered
Affiliates (PPL): LG&E and KU Energy, LLC and PPL Electric Utilities
Corporation. The PPL NERC Registered Affiliates are registered in two regions
(RFC and SERC) for one or more of the following NERC functions: BA, DP, GO,
GOP, IA, LSE, PA, PSE, RP, TO, TOP, TP, and TSP.

1,3,5,6

Joseph Bencomo

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

Joseph Bencomo - LG&E and KU Energy LLC - 1,3,5,6 - SERC,RFC

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1.3. deploy Contingency Reserve, within system constraints, to respond to all
Reportable Balancing Contingency Events, however, it is not subject to
compliance with Requirement R1 parts 1.1 and 1.2 and R3 if:

Suggested solution – Modify language in 1.3 to:

For a Responsible Entity experiencing an EEA, compliance with BAL-002-2 R3 is
not consistent with actions required under the EEA.

An entity experiencing an EEA (or any of the other exemption scenarios in R1.3)
should not be required to restore ACE as stated in R1.1, document the
Reportable BCE as per 1.2 or restore Contingency Reserves to MSSC within the
Contingency Restoration Period as stated in R3.

The language in R1.3 related to an exemption from R1.1 needs to be applicable
to R1 and R3.

BAL-001-2 becomes enforceable 7/1/2016, R2 (BAAL performance) will incent
the appropriate BA/RSG action to a Reportable BCE without forcing action that
could be contrary to interconnect frequency stability. BAL-001-2 has negated the
need for BAL-002-2.

NPCC

New York State Reliability
Council, LLC
Orange and Rockland Utilities
Inc.
New York Independent System
Operator
Hydro-Quebec TransEnergie
Consolidated Edison Co. of New
York, Inc.
Northeast Power Coordinating
Council
Northeast Utilities
Independent Electricity System
Operator
New Brunswick Power
Corporation
Hydro One Networks Inc.
New York Power Authority
Northeast Power Coordinating
Council
Hydro-Quebec TransEnergie
Ontario Power Generation, Inc.
Utility Services
New York Power Authority
Orange and Rockland Utilities
Inc.
Consolidated Edison Co. of New
York, Inc.
National Grid
National Grid

Alan Adamson

David Burke

Greg Campoli

Sylvain Clermont

Kelly Dash

Gerry Dunbar

Mark Kenny

Helen Lainis

Rob Vance

Paul Malozewski

Bruce Metruck

Lee Pedowicz

Si Truc Phan

David Ramkalawan

Brian Robinson

Wayne Sipperly

Edward Bedder

Peter Yost

Michael Jones

Brian Shanahan

NPCC

NPCC

NPCC

NPCC

NPCC

NPCC

NPCC

NPCC

NPCC

NPCC

NPCC

NPCC

NPCC

NPCC

NPCC

NPCC

NPCC

NPCC

NPCC

Region

NPCC--Project 2010-14.1

Group Member Name Entity

Group Name:

Group Information

Lee Pedowicz - Northeast Power Coordinating Council - 10 - NPCC

1

1

3

1

5

8

5

1

10

6

1

9

2

1

10

1

1

2

3

10

Segments

Northeast Power Coordinating
Council
Dominion Resources Services,
Inc.
Northeast Power Coordinating
Council
NextEra Energy, LLC
ISO - New England
The United Illuminating Company NPCC

RuiDa Shu

Connie Lowe

Guy Zito

Silvia Parada Mitchell

Kathleen Goodman

Robert Pellegrini

Region(s)
NPCC

Entity

Northeast Power Coordinating Council

Answer Comment:

1

2

5

10

5

10

8

5

1

“Balancing operations. The Reliability Coordinator ensures that the generationdemand balance is maintained within its Reliability Coordinator Area, which, in
turn, ensures that the Interconnection frequency remains within acceptable limits.
The Balancing Authority has the responsibility for generation-demand-interchange
balance in the Balancing Authority Area. The Reliability Coordinator may direct a
Balancing Authority within its Reliability Coordinator Area to take whatever action
is necessary to ensure that this balance does not adversely impact reliability.”

With the requirements as written, the Responsible Entity should include the
Reliability Coordinator. As defined in the NERC Reliability Functional Model
Version 5 for the Reliability Coordinator, Balancing operations:

10

Lee Pedowicz

Selected Answer:

Segment

NPCC

NPCC

NPCC

NPCC

NPCC

NPCC

Voter

Voter Information

Consolidated Edison Co. of New
York, Inc.

Brian O'Boyle

NPCC

Entergy Services, Inc.

Glen Smith

NPCC

Consolidated Edison Co. of New
York, Inc.

Michael Forte

In addition, the wording in the third bullet of Part 1.3.1 (Part 1.3.1 needs
identification in the draft) needs clarification. For example, if your MSSC is a
resource loss of 400 MW, this Part’s wording would suggest that the depletion of
"Contingency Reserve to a level below its Most Severe Single Contingency"
would refer to a value of less than 400 MW. You might deplete your reserves by

We feel the time requirement to declare an EEA of any level prior to 1.1 being
waived is an unnecessary operations burden during the Contingency Event
Recovery Period. It could result in an entity being non-compliant because
complete recovery is delayed by the time it takes to go through the "declaration"
process. We feel the new standard is adding an exposure to non-compliance
because of the need for the RC to declare an emergency prior to the waiver of the
ACE correction requirement in Part 1.1. Within NPCC there are entities that fill
both the RC role that declares the EOP-002-3 Energy Emergency Alert level, and
the BA role that BAL-002-2 will apply to.

The process used to find the MSSC uses system models and does allow the
modelling of contingencies.
For clarity, suggest revising the wording in the definition. The models themselves
neither identify contingencies nor are contingencies “maintained in”
them. Suggest eliminating the words “…as identified and maintained in the
system models within the Reserve Sharing Group (RSG) or a Balancing
Authority’s area that is not part of a Reserve Sharing Group…”or replacing the
words “identified and maintained in the system models within” with the following:
“identified using system models maintained within…”.

Regarding the wording used to define the Most Severe Single Contingency
(MSSC), as it reads now the MSSC is defined as “The Balancing Contingency
Event, due to a single contingency as identified and maintained in the system
models within the Reserve Sharing Group (RSG) or a Balancing Authority’s area
that is not part of a Reserve Sharing Group, that would result in the greatest loss
...”.

1.4 Restore its Contingency Reserve to at least its Most Severe Single
Contingency before the end of the Contingency Reserve
Restoration
Period.

Consider incorporating Requirement R3 into Requirement R1 by adding the
following Part 1.4:

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250 MW and still have 150 MW remaining to meet another contingency after the
initial event which may be sufficient and not require a waiver. We suspect that the
intention is that all of the MSSC determined value of required reserve is depleted
before the waiver is allowed.

Southwest Power Pool Inc
Southwest Power Pool Inc
Omaha Public Power District
Omaha Public Power District

Jason Smith

Carl Stelly

Mahmood Safi

Jes Gray

Region(s)
SPP

Entity

Southwest Power Pool, Inc. (RTO)

Answer Comment:

1,3,5

1,3,5

2

2

2

Segments

Our review group also noticed that the drafting team uses the acronym ‘RE’
several times (second paragraph on page 4) in the Rationale for Contingency
Reserve Definition section of the standard. We will make the assumption that you
are referring to the term ‘Responsible Entity’. However, we would suggest either
using it as an appositive with the term or removing it from the document
completely. We feel that some confusion will arise amongst the industry on what
‘RE’ is being referred to. For example, ‘RE’ could refer to ‘Regional Entity’ or
‘Registered Entity’.

We would suggest to the drafting teams developing coordinated efforts with the
Alignment of Terms Standards Draft Team (Project 2015-04). The collaborative
efforts would pertain to the revised and newly proposed terms in BAL-002-2
which would help ensure that these terms are included in both the NERC
Glossary of Terms as well as the Rules of Procedure for proper alignment (which
can be addressed in Phase II of their project). Of course, this collaborative effort
would take place once NERC’s BoT and FERC approves the proposed terms and
standard pertaining to this current project.

2

Shannon Mickens

Selected Answer:

Segment

MRO

MRO

SPP

Voter

Voter Information

SPP

Southwest Power Pool Inc.

Shannon Mickens
SPP

Region

SPP Standards Review Group

Group Member Name Entity

Group Name:

Group Information

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 - SPP

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Finally, we would like to suggest to the drafting team once the terms and
standards have been approved by the NERC BoT and FERC to follow up on this
project and ensure that the RSAW be properly aligned with this standard.

Our group understands that the conversation pertaining to the retirement of BAL002-2 is in the distant future. However, we have the concern that there are
current documentation in place that helps serve the industries needs in reference
to the MSSC. With that being said, we feel that BAL-002-2 brings confusion and
redundancy to the industry and we would suggest that the drafting team take into
consideration the retirement of this standard.

In the Rationale section for Requirement R1, the drafting team mentions “The
current EEA levels suggest that when an entity is experiencing an EEA Level 2 or
3 it is short of Contingency Reserves as normally defined to exclude readiness to
curtail a specific amount of Firm Demand. Under the proposed EEA process, this
would only be during an EEA Level 3. In order to reduce the need for consequent
modifications of the BAL-002 standard, the drafting team has developed the
proposed language”. We would ask the drafting team to provide more clarity on
what direction BAL-002-2 is going in reference to the EEA. The rationale states
that the drafting team has developed proposed language. Can we assume this
proposed language is currently in the standard and if so, will this language match
up with the NERC’s process changes to the EEA levels (which hasn’t been
developed yet)? The next question would be….will these process changes be
vetted through the voting process or will it be the law of the land?

IESO
PJM
ISONE
NYISO
ERCOT
CAISO

Ben Li

Mark Holman

Kathleen Goodman

Greg Campoli

Christina V. Bigelow

Ali Miremadi

Region(s)
RFC

Entity

PJM Interconnection, L.L.C.

Answer Comment:

2

2

2

2

2

2

2

Segments

Eliminate draft 6’s hourly obligations; and

·
Clarify that shedding load is not an expected action in order to maintain
reserves.

·

·
Ensure that the definition of BCE does recognize the possibility of the loss
of more than one resource;

·
Ensure that the definition of Most Severe Single Contingency (MSSC) does
not include more than one resource;

·
Provide the risk based parameters (ACE range, Recovery period,
Restoration period) for responding to a Balancing Contingency Event (BCE);

The SRC agrees with the intention of the SDT draft 7 posting to:

2

Albert DiCaprio

Selected Answer:

Segment

WECC

TRE

NPCC

NPCC

RFC

Voter

Voter Information

SPP

SPP

Charles Yeung
NPCC

Region

ISO Standards Review Committee

Group Member Name Entity

Group Name:

Group Information

Albert DiCaprio - PJM Interconnection, L.L.C. - 2 - RFC

Links MSSC to BCE; and

MSSC;
Contingency Event Recovery Period; and
The EEA level referenced in R1.3.1

·
·
·

In particular, the SRC suggests that the linkage between R 1.1 and R1.31 is a
source of ambiguity within the standard because:

The SRC would ask that the SDT to redraft the requirements in more direct terms.
Phrases like “demonstrate recovery” in the requirement section of the standard
can be construed ambiguously and a clear reliability requirement omits
unnecessary words and directly defines the obligation.

Revisions Proposed To Facilitate Clarity

The SRC has characterized its comments in three classifications: those proposed
to facilitate clarity; those proposed to ensure that the focus of requirements
remains on reliability; and those proposed to address other concerns.

The SRC again asks the SDT to remove the language within draft 7’s proposed
CR requirement that ties DCS compliance to the use of CR.

Balancing Contingency Events;

·

The SRC proposes clarifying modifications to definitions for:

·
Links Contingency Reserves (CR) to Disturbance Control Standard (DCS)
compliance.

·

The SRC does not agree with proposed standard wording that:

Requirement R1.3 defines Contingency Reserve deployment;

·

Retaining current draft language:

1.2. document all Reportable Balancing Contingency Events using CR Form 1.

• its Pre-Reporting Contingency Event ACE Value (if its Pre-Reporting
Contingency Event ACE Value was negative); however, any Balancing
Contingency Event that occurs during the Contingency Event Recovery Period
shall reduce the required recovery: (i) beginning at the time of, and (ii) by the
magnitude of, such individual Balancing Contingency Event.

or,

• zero (if its Pre-Reporting Contingency Event ACE Value was positive or
equal to zero); however, any Balancing Contingency Event that occurs during the
Contingency Event Recovery Period shall reduce the required recovery: (i)
beginning at the time of, and (ii) by the magnitude of, such individual Balancing
Contingency Event,

1.1. within the Contingency Event Recovery Period, demonstrate recovery by
returning its Reporting ACE to at least the recovery value of:

R1. The Responsible Entity experiencing a Reportable Balancing Contingency
Event shall:

1.

This organization does not allow readers and entities responsible for compliance
and direct correlation between specific defined obligations and the proposed
exemptions. To facilitate clarity, the SRC offers two recommendations. The first
recommendation preserves much of the current, draft language while the second
recommendation provides more streamlined language:

·
Sub-Requirements of R 1.3 then introduce exceptions for R1.1 (i.e., R 1.3.1
and R 1.3.2).

Requirement R1.1 defines the target ACE correction (range of recovery);

·

the responsible entity:

the following subsequent event(s) occur:

More direct version:

R1.
Unless the Responsible Entity is experiencing any Reliability
Coordinator-declared Energy Emergency Alert Level 1 or higher, is utilizing its
Contingency Reserve to mitigate an operating emergency in accordance with its
emergency Operating Plan, or has depleted its Contingency Reserve to a level
below its Most Severe Single Contingency, , the Responsible Entity experiencing
a Reportable Balancing Contingency Event (RBCE) shall return its ACE to:

1.

•
multiple Balancing Contingency Events within the sum of the time
periods defined by the Contingency Event Recovery Period and Contingency
Reserve Restoration Period whose combined magnitude exceeds the
Responsible Entity's Most Severe Single Contingency.

•
multiple Contingencies where the combined MW loss exceeds its Most
Severe Single Contingency and that are defined as a single Balancing
Contingency Even;, or

1.3.2 the Responsible Entity experiences:

·

or,

•
is experiencing any Reliability Coordinator-declared Energy
Emergency Alert Level 1 or higher; is utilizing its Contingency Reserve to
mitigate an operating emergency in accordance with its emergency Operating
Plan; or has depleted its Contingency Reserve to a level below its Most Severe
Single Contingency .

·

Unless:

1.3. deploy Contingency Reserve, within system constraints, to respond to all
Reportable Balancing Contingency Events, however, it is not subject to
compliance with Requirement R1 part 1.1 if: 1.3.1 the Responsible Entity is:

The SRC does recognize the SDT’s attempt to address the issue of maintaining
reserves designed to preserve serving load verses the issue of shedding load to
preserve reserves and that it makes no sense to shed load to maintain reserves
that are designed to protect load from being shed. Additionally, the SRC
questions the need for the proposed Requirement R2 (i.e., the requirement to
have a method to compute MSSC). Such

The SRC asserts that the primary focus of BAL-002 should be reliability (ACE
recovery) with less focus be given to the specific process regarding how to meet
the reliability requirement. The current draft appears to link economic sharing
arrangements (Contingency Reserves) to a reliability requirement and, therefore,
precludes the use of more effective processes to meet the reliability requirement.
The SRC cautions the SDT against mandating the use of a process where such
usage would be inappropriate from both a reliability and cost efficiency
perspective when other processes are available For example, as written, draft 7
could preclude the use of Demand Side Management (DSM) as Contingency
Reserves (in contradiction of Order 1000), and restricting DSM to Emergencies
only. For these reasons, the requirements should be re-focused on what needs to
occur for reliability – not how such activities are performed.

Revisions proposed to ensure that the focus of requirements remains on
reliability

Where a Balancing Contingency Event exceeds the responsible entity’s MSSC or
multiple Balancing Contingency Events occur within the Contingency Event
Restoration period of the 1st RBCE, the responsible entity shall deploy
contingency reserves, but such response shall not be subject to Requirement R1:

·
Its Pre-RBCE ACE Value if the Responsible Entity’s Pre-RBCE ACE Value
were negative

·
Zero within the Contingency Event Recovery Period if the Responsible
Entity’s Pre-RBCE ACE Value were positive or equal to zero; or

carry an equivalent amount of reserves for that year

carry an equivalent amount of RC (for as long as the plan states)

The SRC suggests the following comments and/or revisions for the SDT’s
consideration:

Revisions Proposed to Address Other Concerns

The definition of MSSC is axiomatic and does not require a formal procedure. The
only plausible justification for having such a plan is mandate self-imposed rules
regarding when to compute MSSC; how to apply that calculation; and for how
long. Given the ambiguity in draft 7’s R2, either approach can be justified. Such
ambiguity would not serve reliability. As an example, if draft 7 really did intend
linking MSSC to an annual value, and in doing so lock-in a minimum reporting
value (80% of MSSC), then what could occur is that small BAs can have a
minimum reportable value that is larger than any unit that is operating on a given
day – in effect - exempting them from ever reporting. On the other hand, if draft 7
really did intend to provide flexibility to the BAs, a number of questions arise: Is
this a daily scheduling function, or a continuous operating function? Is the
objective fixed or does it depend on what is operating at the given
time? Accordingly, the current approach could be interpreted broadly and
variably and should be revised as it does not appear to be directly focused on or
facilitating reliability.

·

·
implement the computation ( the implication is that the plan will introduce
the time frame for updating MSSC)

·
develop a plan to explain how to compute MSSC and review that plan
every year

or

·

·
an annual obligation to compute MSSC and to use that annually-computed
MSSC in system operations, and

requirement is administrative in nature as it mandates a creation of a procedure,
an implementation process for that procedure, as well as a mandate to “have” a
market service to calculate MSSC. The sentence in draft 7 can be read as ether:

The Draft 7 definitions of MSSC and BCE do not resolve the issue of BCE
1.
being greater than the MSSC because Draft 7 continues to link the definitions of
MSSC and BCE. The SRC believes MSSC is an a priori / actual state value while
BCE is an a posteriori event/experience. The SRC agrees with the SDT that
MSSC can never be more than one resource otherwise it would not be a “single
contingency.” BCE on the other hand can (as the current definition indicates)

The SRC requests that the SDT explain its correlation between the reporting
requirement and P 354 and requests that the SDT clarify the timing of any
required reporting. Additionally, the SRC is unclear as to how “the VSL levels
developed were likely to place smaller BA’s and RSGs in a severe violation
regardless of the size of the failure.” Upon review, it appears that values for
entities are calculated on a % of recovery whether applied to an individual event
or quarterly performance – accordingly the severity of a violation would still be
correlated to overall performance for some time period. The SRC requests that
the SDT re-evaluate its explanation and provide additional clarification.

354. First, the Commission directs the ERO to develop a modification to the
Reliability Standard requiring that any single reportable disturbance that has a
recovery time of 15 minutes or longer be reported as a violation of the
Disturbance Control Standard. This is consistent with our position in the NOPR
and NERC’s position in response to the Staff Preliminary Assessment of the
Requirements in BAL-002-0, and was not disputed or commented upon by any
NOPR commenters.

2.
The standard has a reporting requirement, but does not include a reporting
timeframe. Therefore, the most conservative assumption would be that reporting
is on and “individual event” basis. For draft 7, the SDT rejected quarterly
reporting based on a non-relevant paragraph in Order 693.

1.
Delete the phrase “within system constraints” in Requirement R1. Because
BAs are not responsible for system constraints (that’s the role of TOP), the
inclusion of this phrase connotes that a BA can be held responsible for
exacerbating a SOL problem, even if the BA had no knowledge of the limit and
was taking actions to comply with its obligations. The requirements should
respect current roles and responsibilities of the various functions and, currently,
the TOP is responsible for directing the BA in this regard.

Sudden loss of generation:

b. And, that causes an unexpected change to the responsible entity’s ACE;

iii. sudden unplanned outage of transmission Facility;

ii. loss of generator Facility resulting in isolation of the generator from the Bulk
Electric System or from the responsible entity’s System, or

i. unit tripping,

a. Due to

A.

Any single event described in Subsections (A), (B), or (C) below, or any series of
such otherwise single events, with each separated from the next by one minute or
less.

Draft 7 definition of Event:

Most Severe Single Contingency (MSSC): The Balancing Contingency Event,
due to a single contingency as identified and maintained in the system models
within the Reserve Sharing Group (RSG) or a Balancing Authority’s area that is
not part of a Reserve Sharing Group, that would result in the greatest loss
(measured in MW) of resource output used by the RSG or a Balancing Authority
that is not participating as a member of a RSG at the time of the event to meet
Firm Demand and export obligation (excluding export obligation for which
Contingency Reserve obligations are being met by the Sink Balancing Authority).

Draft 7 definition of MSSC:

include the impacts of the loss of more than one resource. To address this
concern, the SRC offers the following comments and revisions.

The Draft 7 definition CR does not define what CR is, but rather defines what CR
may be used for. Moreover, the definition’s use of the phrase “provision of
capacity” requires further explanation to clearly delineate between the concept of
“provision of capacity” in the Operating Planning environment (meaning to
request that resource be made available to serve load) versus the “provision of
capacity” in the compliance/operating environment (meaning the amount of

·
Can be used to provide clarity concerning why and how the amount of CR
can be set to a daily MSSC; and how and why every CBE can be “reported” upon
without being subject to the DCS objectives for an MSSC.

·
Changes the MSSC definition from being linked to a Balancing
Contingency Event of undefined size, to linking MSSC to an easily identified
single resource capacity/expectation.

This revision:

MSSC is the MW capacity of the single largest resource scheduled to operate for
a given day’s peak load. The resource may be a generator (Maximum Continuous
Operating Capacity) or a Firm Interchange scheduled import.

The SRC would suggest that Draft 7 definition of Event be retained, but that the
definition of MSSC be redrafted. The SRC suggests:

Given the above definitions, the SRC concludes that the SDT correctly wants to
ensure that MSSC include large interchange schedule imports as well as large
generators. The definition of BCE does that (see sub item B). The draft 7
definition of MSSC relies on the definition of BCE to ensure that such interchange
gets considered. The problem is that the foreword of the BCE definition includes
the phrase “or any series of such otherwise single events.” That addition makes it
virtually impossible to quantify / limit one single resource amount for an MSSC.

C. Sudden restoration of a Demand that was used as a resource that causes an
unexpected change to the responsible entity’s ACE.

B. Sudden loss of an import, due to unplanned outage of transmission
equipment that causes an unexpected imbalance between generation and
Demand on the Interconnection.

·
Reserves were linked to day ahead scheduling in the sense that “reserve”
capacity over and above the capacity scheduled to meet a peak load. This
concept was referenced in the original Policy 1 – Generation Control and
Performance, (dated Feb 1, 1997) at romanette ([i]) If CR were viewed as
scheduled available system capacity there would be no issue, because then the
measurement of reserves would be focused on the planned capacity for the day.
Once that capacity is synchronized it can be used for any and all purposes.

The SRC suggests that the issue of CR and reserves in general requires an
Industry-wide review; and the SDT in its introduction to its Response to
Comments propose the ERO conduct such a review prior to making a decision on
a final ballot. The review would be used to decide if:

• is utilizing its Contingency Reserve to mitigate an operating emergency in
accordance with its emergency Operating Plan.

• is experiencing a Reliability Coordinator declared Energy Emergency Alert
level, and

Draft 7 definition of Contingency Reserve: The provision of capacity that may
be deployed by the Balancing Authority to respond to a Balancing Contingency
Event and other contingency requirements (such as Energy Emergency Alerts as
specified in the associated EOP standard). A Balancing Authority may include in
its restoration of Contingency Reserve readiness to reduce Firm Demand and
include it if, and only if, the Balancing Authority:

Draft 7 definition of Contingency Reserves

energy that was produced at the request of the BA). An additional issue with the
first sentence is that, as written, it specifically excludes the use of those reserves
to serve firm customer load. To address this concern, the SRC offers the
following comments and revisions.

SRC - 2010-14-1 (BAL-002-2) .docx
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• is experiencing a Reliability Coordinator declared Energy Emergency Alert
level where an energy deficient BA is not able to maintain minimum Contingency
Reserve requirements, and

Contingency Reserve: The resource capacity, measured in MW, above that
serving Firm Demand, that may be deployed by the Balancing Authority to
respond to a Balancing Contingency Event and other contingency requirements
(such as Energy Emergency Alerts as specified in the associated EOP standard).
A Balancing Authority may include in its restoration of Contingency Reserve
readiness to reduce Firm Demand and include it if, and only if, the Balancing
Authority:

We propose the following changes for clarity.

Contingency Reserve: As written, the criteria for allowing readiness to reduce
Firm Demand in Contingency Reserve is ambiguous. We suggest adding
clarifying language to clearly state when the readiness to reduce Firm Demand
will be accepted as Contingency Reserve.

Most Severe Single Contingency (MSSC): The loss of a single Element as
identified and maintained in the system models within the Reserve Sharing Group
(RSG) or a Balancing Authority’s area that is not part of a Reserve Sharing
Group, or the sudden loss of an import, or the sudden restoration of a Demand
that was used as a resource, that would result in the greatest loss (measured in
MW) of resource output used by the RSG or a Balancing Authority that is not
participating as a member of a RSG at the time of the event to meet Firm
Demand and export obligation (excluding export obligation for which Contingency
Reserve obligations are being met by the Sink Balancing Authority).

MSSC: As written the MSSC definition is linked to and dependent on the
definition of a Balancing Contingency Event. In doing so an RE must determine
its MSSC based on a Balancing Contingency Event, or series of events including
imports, separated by one minute, that have not occurred. As long as the
definition of MSSC is dependent on the definition of a BCE, we suggest that
MSSC is incalculable and propose the change below.

Definitions

We would like to thank the SDT for their work on this proposed revision to BAL002-1 and the opportunity to provide comments.

Mark Holman - PJM Interconnection, L.L.C. - 2 -

• utilizing its Contingency Reserve to mitigate an operating emergency in
accordance with its emergency Operating Plan, and

• experiencing a Reliability Coordinator declared Energy Emergency Alert
Level where an energy deficient BA is not able to maintain minimum Contingency
Reserve requirements, and

1.3.1 the Responsible Entity is:

1.3. respond to all Reportable Balancing Contingency Events, which may include
the deployment of Contingency Reserve, however, it is not subject to compliance
with Requirement R1 part 1.1 if:

Accordingly, we propose the changes below.

Additionally, we suggest that the phrase “within system constraints” should be
removed because BA’s are not responsible for system constraints; that being the
role of the TOP. The TOP standards address system constraints and the TOP is
responsible for directing the BA in this regard.

We also recognize that the BAAL limits defined in the recently approved BAL001-2 ensure that an RE will take all available actions to respond to a Reportable
Balancing Contingency Event and support Interconnection frequency.

For example, using the PJM minimum synchronized reserve requirements (100%
of MSSC, or approximately 1400MW deployed via All-Call) and regulating
reserves (+/- 700MW during peak hours); language that suggests a mandatory
deployment of Contingency Reserve could result in well over 2100MW,
responding to a 900MW reportable event. This response could be much higher
since synchronized reserves are typically much greater than the 1400MW
requirement and regulation alone could result in 1400MW of response.

We understand the intent of the SDT, however, R1.3 states that an RE must
deploy Contingency Reserve for all Report Balancing Contingency Events
regardless of whether there is a need to deploy Contingency Reserve to comply
with R1.1. Recovery is often accomplished through frequency responsive and
regulation resources. Additionally, R1.3 as written could be interpreted to mean
that an RE shall deploy ALL available Contingency Reserve, which could be well
above MSSC, for ALL Reportable Balancing Contingency Events which could
have an adverse impact on Interconnection frequency and BES reliability.

Requirement 1:

• is utilizing its Contingency Reserve to mitigate an operating emergency in
accordance with its emergency Operating Plan.

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Answer Comment:

Selected Answer:

EOP-011 states that a Level 2 EEA is "The Balancing Authority is no longer able
to provide its expected energy requirements and is an energy deficient Balancing
Authority." meaning all available resources are in use serving load; and " An

ISO New England does not agree with the SDT's position that an EEA Level 3 is
necessary in order to support an exemption from R1. If this were elevated to
Level 3 that would imply shedding load in order to maintain reserves and ISO
New England understands that this was not the intent.

Kathleen Goodman - Kathleen Goodman On Behalf of: Michael Puscas, ISO New England, Inc., 2

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With the addition of Requirement 3, either R1.2 should be removed from the
standard or the CR Form 1 should be modified to demonstrate Contingency
Reserve restoration including subsequent Balancing Contingency Events that
may occur within the Contingency Event Restoration Period so that compliance to
a Reportable Balancing Contingency Event can be demonstrated with a single
document.

Requirement 3:

R2. Each Responsible Entity shall develop, review and maintain annually, and
implement an Operating Process as part of its Operating Plan to determine its
Most Severe Single Contingency and make preparations to have available
Contingency Reserve equal to, or greater than the Responsible Entity’s Most
Severe Single Contingency. [Violation Risk Factor: Medium] [Time Horizon:
Operations Planning]

We propose the following changes to Requirement 2 to add clarity.

Requirement 2:

• the Responsible Entity has depleted its Contingency Reserve to a level
below its Most Severe Single Contingency

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2.
ERCOT reiterates the need to revise Requirement 1 to provide obligations
in more direct terms and with additional clarity and reiterates its comments
regarding burdensome and administrative nature of the individual reporting
requirement contained within Requirement R1.2 for individual Reportable
Balancing Contingency Events. Such reporting does not benefit reliability and
could obscure trends or other characteristics that would be obviated by reporting
over a longer time period. Perhaps the SDT could consider a time period that is

1.
Definitions – ERCOT reiterates its previous comments regarding the
Reportable Balancing Contingency Event thresholds contained within the
definition of a Reportable Balancing Contingency Event. ERCOT believes that
the introduction of various, differing thresholds creates unnecessary complexity
and would propose a 1000 MW threshold for its interconnection as such threshold
aligns with the current practice. Further, ERCOT reports other, smaller events to
NERC and its Regional Entity through different mechanisms and, therefore, with
differing reporting thresholds, the same event can be reported to NERC multiple
times under different requirements. Accordingly, since the threshold limits relate
only to reporting and associated documentation, ERCOT respectfully submits that
lowering the reportable event thresholds does not provide any benefit to reliability.

ERCOT commends the drafting team on their efforts to improve BAL-0022. However, it has concerns and recommendations regarding the proposed
modifications. ERCOT supports and incorporates into its comments by reference
the comments submitted by the ISO/RTO Council Standards Review
Committee. Additional concerns and recommendations are described below by
Requirement. Proposed revisions are italicized.

christina bigelow - Electric Reliability Council of Texas, Inc. - 2 -

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energy deficient Balancing Authority is still able to maintain minimum Contingency
Reserve requirements." which given the first instance can only be accomplished
through arming for load shed to cover the reserves if a contingency were to occur.
In the alternative, this would mean shedding actual customer load to maintain
reserves before the contingency actually occurs, which is not in the best interest
of Reliability.

Document Name:

ERCOT thanks you for the opportunity to comment upon the proposed Revisions
to BAL-002-2. Should the ERO wish to provide additional guidance regarding the
mix or management of Contingency Reserves, it should consider the
development and publication of a Reliability Guideline.

ERCOT suggests this alternative because the identification of MSSC is subject to
criteria and are part of an overall process to be performed. Further, the proposed
requirement presumes a particular structure for responsible entity’s compliance
processes and procedures that designates the “how” of meeting the requirement
instead of the “what.” The proposed revision preserves the objective of the
proposed Requirement 2 while ensuring that the requirement is results-based and
respectful of the various administrative structures established within various
entities to administer compliance-related documentation and processes.

· Evidence to indicate that the processes have been reviewed and maintained
annually.

• Documentation of its processes for identification of the MSSC and
procurement of contingency reserves equal to or greater than its Most Severe
Single Contingency; and

• Criteria for determination of the MSSC;

M2. Each Responsible Entity will have the following documentation to show
compliance with Requirement R2:

Compliance may be achieved by demonstrating that:

Measure 2 could then be modified as follows:

Each Responsible Entity shall document and implement its criteria for
identification of MSSC and its processes for review of MSSC and for procurement
of contingency reserves greater than or equal to the identified MSSC, which shall
be reviewed no less than annually.

3.
Requirement R2 –ERCOT respectfully submits that, as proposed,
Requirement R2 adds potentially onerous and unnecessary administrative
processes and documentation to what has, historically, been a simple, wellestablished process regarding identification of the MSSC and the procurement of
appropriate contingency reserves. To simplify this requirement while retaining the
reliability-related aspects of its objective, ERCOT offers the following revisions for
the SDT’s consideration:

shorter than quarterly, but clarify that reporting is not on an individual basis
triggered by individual events.

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Great River Energy
Hoosier Energy Rural Electric
Cooperative, Inc.
Prairie Power, Inc.

Mike Brytowski

Bob Solomon

Ginger Mercier

6
Region(s)

Ben Engelby

Entity

Answer Comment:

Selected Answer:

1,3

1

1,3,5,6

1,4,5

Segments

(2)
We are disappointed that the SDT has not responded or addressed our
previous concerns regarding the “Most Severe Single Contingency”
definition. From the definition, we believe the applicability reference should be
removed entirely. We recommend the definition should read “A Balancing
Contingency Event, as identified by the Responsibility Entity and maintained in its
system models, that would result in the greatest loss of resource output at the
time to meet Firm Demand and export obligations, excluding those export
obligations for which Contingency Reserve obligations are being met by a Sink
Balancing Authority.” We also recommend the removal of the MW measurement,
a unit of power, as a Balancing Contingency Event is a moment in time.

(1)
We applaud the SDT on its efforts to clarify the language of the standard
and respond to our previous comments. We continue to believe the SDT is
heading in the correct direction during the development of this standard.
However, we still have concerns regarding the language, scope, and
implementation plan.

ACES Power Marketing

Segment

SERC

RFC

Voter

Voter Information

WECC

Arizona Electric Power
Cooperative, Inc. Southwest
Transmission Cooperative, Inc.

John Shaver

MRO

Region

ACES Standards Collaborators - BARC Project

Group Member Name Entity

Group Name:

Group Information

Ben Engelby - ACES Power Marketing - 6 -

(8)
We have concerns with the VSLs identified for Requirement R1. We
agree with the SDT’s conclusions that the measured contingency reserve
response and required recovery value of Reporting ACE, when is adjusted for
other Balancing Contingency Events that occur during the Contingency Event

(7)
We feel the SDT is overcomplicating the language of Requirement
R1. We concur that clarification is needed in the instance when a Balancing
Contingency Event follows a single Reportable Balancing Contingency
Event. However, embedding a reference to identify what is and isn’t required
within the same requirement is cumbersome. We recommend moving the
embedded reference to another requirement and identify the Contingency Event
Recovery Period only applies to a single event.

(6)
The SDT should consider moving all standard-specific definitions to the
NERC Glossary of Terms.

(5) Under certain situations, a Responsible Entity may not be aware of the
significance of a Balancing Contingency Event. For the definition of Contingency
Event Recovery Period, the SDT should clarify that the recovery period should
not start with the initial decline of resource output, but the instance when ACE
reaches the reportable threshold of a Reportable Balancing Contingency Event
and fifteen minutes thereafter.

(4)
The SDT needs to address our previous comments regarding the
“Reportable Balancing Contingency Event” definition. We recommend the
removal of “Prior to any given calendar quarter...” from the definition, as it implies
the need for an additional requirement for Responsible Entities to coordinate an
exception from the rest of the definition which is based on a percentage of the
MSSC or an Interconnection-based amount. Furthermore, we continue to believe
that the thresholds in the definition are arbitrary, and ask that the drafting team
provide a technical basis for these values. In many cases, the values selected
are below the median values identified in Attachment 1 of the background
document. By not documenting the more frequently occurring values annually,
we fear this could cause issue later on in the standard development process. We
recommend moving the identification of these values, and supporting background
for their selection, to an attachment within the standard, similar to the approach
taken in NERC Standard BAL-001-2.

(3)
Likewise, we wish the SDT would further clarify this standard’s
applicability. We understand the need to address the instance when a BA fails to
meet the membership requirements of a Reserve Sharing Group (RSG). We
recommend that Section 4.1.1.1 should be split as follows, “4.1.1.1 A Balancing
Authority is the Responsible Entity that is not a member of a Reserve Sharing
Group” and “4.1.1.2 A Balancing Authority that is a member of a Reserve Sharing
Group and is the Responsible Entity only in periods during which the Balancing
Authority is not in active status under the applicable agreement or the governing
rules for the Reserve Sharing Group.”

(14) We feel that the bullets of Requirement R1.1 and Requirement R3 are
redundant in reference to “any Balancing Contingency Event that occurs during
the Contingency Event Recovery Period.” We suggest removing the redundant
bullets in Requirement R1.1 for clarity, and instead expand Requirement R3 to
include a reference to magnitude.

(13) We disagree with the VSLs identified for Requirement R3 that measure
the percentage of Contingency Reserve restoration. The requirement identifies
the required time that such restoration must be completed. We recommend
replacing with the form “The Responsible Entity restored less than x% but at least
y% of required Contingency Reserve following the conclusion of the Contingency
Event Restoration Period.”

(12) If the intent of the SDT to have Responsible Entities use CR Form 1, then
we recommend adding its use in Measure M3 and in the RSAW for R3. A
Responsible Entity is already able to use the form to demonstrate its deployment
of Contingency Reserve, within system constraints, then it should be able to
reuse the form to demonstrate the restoration of Contingency Reserve within the
Contingency Reserve Restoration Period.

(11) In reference to Requirement R2, we question the need to review an
Operating Plan, as such action is already implied with an Entity is “maintaining”
their plan. We believe the language identified should be aligned with the
language listed within NERC Standard EOP-010-1.

(10) We recommend the removal of “all Reportable Balancing Contingency
Events” as a condition listed in Requirement R1.3. This condition is already
referenced in R1. We believe rewording Requirement R1.3 to read “…deploy
Contingency Reserve, within system constraints, except when not subject to
compliance with Requirement R1 part 1.1 if…” would still satisfy the requirement.

(9)
We acknowledge the SDT for its response to our previous comments
regarding Requirement R1.2. However, we still feel that a requirement for
documenting events in a spreadsheet is administrative in nature, and could even
be classified as a P81 requirement, as its violation would never result in a harm to
BES reliability, especially at a Medium level risk to operations. If an entity only
identifies the MW loss and date and time of the event, yet leaves the rest of the
form blank, would this result in a violation? As written, the answer would be no,
although an incomplete form would not meet the intention of the SDT to provide
consistent reporting. We recommend the SDT identify the criteria needed for
uniform reporting in a separate attachment to the standard and remove
administrative tasks that meet Paragraph 81 criteria.

Recovery Period, are mathematically equivalent. However, the VSLs are based
on one approach while the spreadsheet is based on the other. We recommend
the SDT select one approach and use it consistently throughout the standard.

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(18)

We thank the SDT for this opportunity to comment on this standard.

(17) We recommend the SDT fix the title page of the background document to
include the document’s title, “Disturbance Control Performance - Contingency
Reserve for Recovery from a Balancing Contingency Event Standard Background
Document.”

(16) We observe a typographical error within the Implementation Plan
regarding the definition of Most Severe Single Contingency. We recommend the
removal of the “that is not part of a Res area” reference. The definition should
then read “…within the Reserve Sharing Group (RSG) or a Balancing Authority’s
area that not part of a Reserve Sharing Group…”

(15) We caution the SDT that references to the term “Reporting Area Control
Error” in the rationale for Requirement R1 goes into effect July 1, 2016. The
Implementation Plan references that the standard would go into effect six months
after FERC approval. Since this term is critical to the definition of “Pre-Reporting
Contingency Event ACE Value”, we recommend an update to the Implementation
Plan to July 1, 2016 or later as the effective date.

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If the Reportable Disturbance occurs when frequency is above Scheduled
Frequency, as over-response required by the Balancing Authority to ensure
compliance with BAL-002 may cause the Balancing Authority to be above its high
BAAL under BAL-001-2.

Example of loss of generation in the middle of the night:

Now that BAL-001-2 is approved, there will be another standard driving a BA to
take corrective action in certain situations where compliance with BAL-002 may
have a detrimental impact on Interconnection frequency.

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Mike ONeil - NextEra Energy - Florida Power and Light Co. - 1 -

0

Texas RE recommends the VSL for R3 should include Requirement language “at
least its Most Severe Single Contingency”.

Texas RE noticed the VSL for R2 does not address the review annually portion of
the Requirement. VSL should be changed to include “maintain annually”.

Texas RE noticed the VSL for R1 does not address R1.3. The language for R1.3
should be included.

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Rachel Coyne - Texas Reliability Entity, Inc. - 10 -

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Introduction

While NaturEner largely supports the proposed changes to BAL-002-2, NaturEner
believes the standard can be, and should be, even further improved. Specifically,
NaturEner recommends that the definition of “Balancing Contingency Event”
should be further modified to explicitly include as a qualifying event an
unpredicted loss of generation capability. While generator-neutral, the explicit
inclusion of this type of event has particular and extreme importance to variable
(i.e., renewable) generation, which due to the current inherently imprecise nature
of forecasting, unavoidably experience such events at times. The sole reason
that NaturEner has abstained in this balloting process, rather than voting
affirmative, is because NERC’s proposed definition does not explicitly include as
a qualifying event an unpredicted loss of generation capability.

NaturEner USA, LLC and its subsidiaries (“NaturEner”) largely support the
proposed changes to BAL-002-2, which move the standard towards a
performance-based measure of disturbance control response.

I.

Jamie Lynn Bussin - NaturEner USA, LLC - 5 -

0

Now that BAL-001-2 is approved, there will be another standard driving a
Balancing Authority to take corrective action in certain situations where
compliance with BAL-002 may have a detrimental impact on Interconnection
frequency. One example would be if there is a loss of generation in the middle of
the night. If the Reportable Disturbance occurs when frequency is above
Scheduled Frequency, as over-response by the Balancing Authority to ensure
compliance with BAL-002 may cause the Balancing Authority to be above its high
BAAL under BAL-001-2.

Likes:

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Answer Comment:

Selected Answer:

Jennifer Losacco - NextEra Energy - Florida Power and Light Co. - 1 - FRCC

Due to
unit tripping,

a.
i.

And, that causes an unexpected change to the responsible entity’s ACE;

b.

unpredicted loss of generation capability.

II.

Reasoning

Revising that definition as suggested is consistent with the underlying reasons for
specifying certain events as Balancing Contingency Events, as NaturEner’s
suggested revision reflects sudden and unavoidable events affecting the grid, and
also supports the efficient and effective deployment of resources and the
integration of renewable resources. Moreover on a broader basis, though such a
revision to the definition is not required for reserve sharing groups to include
unpredicted loss of generation capability as a qualifying contingency event under
which reserve contingencies can be called upon, such a revision to the definition
can only help ongoing efforts to encourage reserve sharing groups who have not
yet approved such occurrences as qualifying events to do so now.

iv.

NaturEner recommends that the definition should be revised to add a fourth
clause to subsection A.a.:

C.
Sudden restoration of a Demand that was used as a resource that causes
an unexpected change to the responsible entity’s ACE.

B.
Sudden loss of an import, due to unplanned outage of transmission
equipment that causes an unexpected imbalance between generation and
Demand on the Interconnection.

sudden unplanned outage of transmission Facility

iii.

ii.
loss of generator Facility resulting in isolation of the generator from the Bulk
Electric System or from the responsible entity’s System, or

Sudden loss of generation:

A.

Balancing Contingency Event: Any single event described in Subsections (A),
(B), or (C) below, or any series of such otherwise single events, with each
separated from the next by one minute or less.

NERC’s suggested changes to BAL-002-2 propose the following definition of
Balancing Contingency Event:

The exclusion of extreme loss of wind or solar events from qualifying contingency
events leads to at least two negative consequences. First, because the
calculation of the resource requirements do not consider regional diversity, the
sum of the resource requirements calculated at each individual Balancing
Authority-level are much larger than what would be calculated at a system-wide
level, leading to systematic over-procurement. Second, due to the increase in
capacity resulting from this approach, wind integration tariffs have been
implemented in some Balancing Authorities, chilling the ability of new renewable
generation to come online in some regions. In contrast, the Midwest ISO has
been progressive in implementing market initiatives and programs to enable
flexibility in its system and has not needed to increase its reserve capacity as its
renewable penetration has increased. The Southwest Power Pool is also a
system which has been recognized as a leader in variable integration, and its

For conventional generating units in the west, there are few limitations on the
cause or frequency of qualifying contingency events. This is consistent with the
underlying purpose and rationale of a reserve sharing group - that there are
various extreme events which are unpredictable, unavoidable, and can impact
reliability. By pooling the resources of participating Balancing Authorities,
reliability can be maintained without requiring individual Balancing Authorities to
carry 100% of MSSC in reserves. This is beneficial to the grid, because it avoids
costly over-procurement of capacity, while still ensuring the reliability of the
system as a whole. The low likelihood that multiple contingencies will occur at
the same time means that this shared capacity can be relied upon to be
sufficient. Large rapid loss of wind (and solar) events are similarly consistent with
the underlying purpose and rationale of a reserve sharing group, in that they there
are extreme events which are unpredictable, unavoidable, and can impact
reliability. Moreover, if they are appropriately defined and evaluated over a
geographically diverse area, they are unlikely to occur at the same time.

NaturEner takes wind power forecasting extremely seriously, and has invested
significant resources to improve our ability to accurately schedule our generation
onto the grid. However, there are some weather events that are extremely
difficult to forecast and can cause wind generation units to lose generating
capability quickly and unexpectedly. These can result from events such as a
sudden change in wind direction due to changing weather regimes or localized
effects, or from other complex weather interactions which are not well-captured
by state of the art forecasting techniques. Though these events are outside of
our control and can result in a sudden and large unpredictable loss of generation,
such events are currently not recognized as qualifying events in some regional
reserve sharing groups.

NaturEner collectively is the owner of three wind farms, the Glacier Wind 1 wind
farm, the Glacier Wind 2 wind farm, and the Rim Rock wind farm, as well as two
wind-based balancing authorities, NaturEner Power Watch, LLC and NaturEner
Wind Watch, LLC.

Even if and when an EIM is present, however, it still will likely not adequately
resolve the problems from unpredicted loss of generation capability unless
designed appropriately. It may still cause individual Balancing Authorities to
procure more reserve capacity and related transmission than is required to
reliably operate the system as a whole. In discussion regarding implementation
of an EIM, a resource sufficiency (RS) methodology is being considered by the
NWPP to verify that EIM participants enter the scheduling hour with sufficient
resources. The work being done in this respect is thoughtful and
important. However, the efforts currently being considered also highlight a gap in
the existing system in the west. In order to require that participants come to the
market “Firm for the hour”, an analysis of the error frequency distribution

The risk of unnecessary reserve build-outs and holdbacks may be alleviated to
some extent if a regional energy imbalance market (“EIM”) is implemented,
because the market would settle every 5 minutes, thereby resolving the time
constraints outlined in our previous comments. However, RBC will come into
effect prior to any operational EIM in the WECC. This may in fact result in a
system-wide increase in capacity required to be held in reserve and unnecessary
reservation of related transmission, and their associated costs.

With the conversion of BAL-001 to the BAAL standard, the standard approach of
using a “CPS2 Analysis” to determine the reserves required to operate reliably
will become obsolete. At this point, the timing issue which NaturEner raised in its
January 26, 2015 FERC comments to the proposed rulemaking regarding BAL001 (FERC 20150126-5252, RM14-10) will become more important (in fact,
FERC in its Order in that RM14-10 proceeding, suggested that NaturEner raise
the subject matter set forth in these comments in this NERC proceeding (151
FERC ¶ 61,048, at page 26, footnote 72)). In a CPS2 analysis, the monthly ACE
is evaluated to ensure that reserves are sufficient such that 90% of the 10 minute
periods are within L10, regardless of the magnitude. In a BAAL analysis, the
ACE will have to be evaluated such that any single 30 minute period should not
exceed the BAAL limits. Due to the timing constraints of 15 minute scheduling
and the 30 minute BAAL timer, there will be some ACE events which cannot be
resolved by modifying interchange schedules. To ensure that a RBC violation
will not occur, BA reserves will need to be carried which can resolve the largest
such event which could be observed. This will result in an increase in the
inefficient deployment of capacity and related transmission reservations in order
to maintain compliance for unpredicted loss of generation capability events unless
such events qualify as recognized balancing contingency events.

reserve sharing group makes no limitations on what the cause of a qualifying
event is, only that it should be a loss of generation greater than 50 MW. Also with
respect to two different weather-related events which result in a loss of
generation, members of the Northwest Power Pool (NWPP) are currently allowed
to call contingency reserves for high-speed cutouts and for temperature
extremes.

In order to demonstrate the impact of system-wide aggregation on the reliability of
wind generators, the NREL western wind data set [1]from 2006 was used to
generate a histogram of the forecast error associated with a regionally diverse
subset of the NWPP member states included in that data set. The forecast was
assumed to be 30 minute persistence, held constant for the full operating
hour. The hysteresis-corrected SCORE value was used to include the impact of
both loss of wind and high speed cutouts. A comparison of applying this
approach to reserve requirements for both an aggregated 10,000 MW system and
an individual 100 MW site are shown in Figure 1 and Figure 2 below. It can be
seen that there is much more volatility relative to the installed capacity, which is a
result of geographical diversity (i.e., a higher volatility is calculated the smaller the
geographic footprint). Further, it can be seen in Figure 2 below that if the
proposed resource sufficiency approach was applied at an aggregate system
level, and reserve requirements to reach 95% reliability were allocated pro-rata,
only 2% of installed capacity would be required. If the individual site level was
evaluated to determine the 95% reliability requirements, then the requirements
would be 8% or installed capacity, or 4 times what is needed by the system in
aggregate. Also note that the NREL data set appears to underestimate the
volatility in in the western region, so the actual realized requirements are higher
than estimated by that approach.

For smaller Balancing Authorities such as ours, this is a catch-22. To integrate
our wind with the system, we want (and should want) to participate in the
EIM. However, due to the resource sufficiency requirement, the amount of
reserves that a Balancing Authority would need to carry would remain unchanged
from the current business as usual because the resource sufficiency
requirements still assume the scheduling time frames currently in place, and does
not allow the benefits of diversity to be included in the assessment of those
requirements. For larger Balancing Authorities, this may not seem to be a
problem now, because they may currently have sufficient internal diversity and
reserves in their own system to cover the current requirements. However, as load
and generation variability continue to increase, thereby requiring capacity
reserves to be increased under the considered EIM-related reserve requirements,
this inefficiency will also impact those entities, and by extension the cost to the
underlying retail consumer.

associated with a Balancing Authority is being done to evaluate error across the
next operating hour, using a persistence forecast from 30 minutes prior to the
hour. Required reserve capacity will be determined based on a selected
probability of events which would exceed that capacity. This work is ongoing, so
it is not clear what the final parameters will be, but a probability of 95% has been
examined. This analysis will be done on a Balancing Authority level (as opposed
to a system-side/reserve sharing group level), and the result of this calculation will
be the required reserve capacity needed to allow participation in the EIM.

Recommendations

Due to
unit tripping,

a.
i.

sudden unplanned outage of transmission Facility, or
unpredicted loss of generation capability

Other Suggested Recommendations.

iii.
iv.

B.

ii.
loss of generator Facility resulting in isolation of the generator from the Bulk
Electric System or from the responsible entity’s System,

Sudden loss of generation:

A.

Accordingly, NaturEner requests that NERC revise the definition of “Balancing
Contingency Event” to add a clause iv. to subsection A.a. providing for
unpredicted loss of generation capability, so that that subsection will then read as
follows:

A.
Revise the Definition of “Balancing Contingency Event” to Include
Unpredicted Loss of Generation Capability.

NaturEner is extremely appreciative of the work that NERC, WECC, PEAK and
the NWPP are doing to improve the efficiency and reliability of the grid. Though
the issues that we have raised here may have a greater impact in the near term
on smaller Balancing Authorities such ours as compared to larger balancing
authorities, as shown above the issues represent a detriment to all grid
participants and the consumer, an unnecessary and avoidable hurdle (especially
to renewable generation), and an inefficient allocation of capacity reserves and
related transmission.

III.

Figure 3: Comparison of Reserve Requirement Calculated on Aggregate vs
individual statistics

The impact of calculating a resource sufficiency for an individual site as opposed
to an aggregate system is shown in Figure 3 below. On that chart, the x-axis
represents the size of the project being evaluated, and the y-axis represents the
resource sufficiency requirements calculated using a 95% probability. It can be
seen that as the installed capacity reaches about 1,000 MW, the required
reserves on a system wide level drop to 2-3% of installed capacity. In the
extreme case where the reserves were calculated at the each individual site level,
then the result would be 4 times higher.

BAL-002 Supporting Diagrams of Comments 2015-08-20.docx
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Devon Yates, Manager, Operational Analytics, NaturEner USA, LLC

a.
Failure to do this will result in inefficient and unnecessary acquisition and
deployment of capacity and related transmission.

3.
Resource sufficiency should be evaluated at a system-wide level, as
opposed to at the individual Balancing Authority-level.

a.
Doing so would encourage participation in EIMs, while centralizing the
planning for contingency management.

2.
Requirements for resource sufficiency in energy imbalance markets should
be aligned with specified qualifying contingency events in regional reserve
sharing groups.

b.
Alternately, the historical contingency events of conventional generators
could be evaluated to provide a benchmark for defining the allowable frequency
of allowable variable generation contingencies.

a.
Qualifying events could be defined using a reasonable persistence
probability of exceedance approach.

1.
Efforts should be made to encourage regional reserve sharing groups to
allow unpredicted loss of generation capability events as qualifying contingency
events, to the extent events are not already allowed by such groups.

In addition to revising the definition of “Balancing Contingency Event“ as
suggested above, NaturEner suggests that NERC’s providing of support and
encouragement for the following considerations wherever appropriate would also
help both alleviate the problems and advance the benefits discussed above.

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Answer Comment:

Selected Answer:
I am voting NO for the following reasons:

Spencer Tacke - Modesto Irrigation District - 4 -

0

Please provide a technical justification for the varying thresholds in the different
Interconnections. It is unclear why the threshold in the Western Interconnection
would be vastly lower than the threshold in ERCOT or even than the Eastern
Interconnection. For example, there are 50 units with a PMAX of 500 MW or
greater in the Peak RC Area. This is a significant number that will lead to more
DCS events that do not significantly impact reliability but will distract from other
key monitoring activities.

The language in R1.1 is confusing with respect to the expectations for multiple
Balancing Contingency Events. Please provide an example of the required
recovery magnitude and timeline of multiple Balancing Contingency Events.

While the SDT has responded to comments on the term “sudden” by saying the
word does “not need further definition as any definitive definition would be
somewhat arbitrary and possibly illǦ fitting for one size entity while perfectly
reasonable for another,” Peak continues to believe that lack of a clear definition
may cause confusion, disagreement and inconsistency. Absent further clarity in
the standard, Peak plans to continue to interpret “sudden loss of generation” as
instantaneous or when the breaker trips.

Likes:

Document Name:

Answer Comment:

Selected Answer:

Jared Shakespeare - Peak Reliability - 1 -

0
0

Likes:

Dislikes:

Document Name:

[email protected]

209-526-7414

Modesto Irrigation District

Senior Electrical Engineer

Spencer Tacke

Sincerely,

Thank you.

Under the Rationale for Requirement R1 on page 7, the phrase
4.
“..returns its Area Control Error (ACE) to defined values…” should include a
locational reference to the actual defined values (i.e., what are they and where
can they be found ?).

Under the Contingency Reserve Restoration Period definition on page
3.
4, the period should be 30 minutes instead of 90 minutes in order to be
consistent with the NERC TOP-004 (Transmission Operations) Standard.

2.
Using arbitrary MW definitions for each major Interconnection (on page 4)
under the same section on the definition of a Reportable Balancing
Contingency Event, may lead to inconsistent results, as the MW values actually
needed are dynamic and based on the amount of load and on-line generation at
the time of the disturbance or contingency event.

1.
A specific percent change in ACE (Area Control Error) needs to be
specified in the definition of Reportable Balancing Contingency Event, where it
states “…sudden decline in ACE based on EMS scan rate…” (on page 3).

1. We request clarification on the “system models” information.
2. We would like to request clarification on the clock-hour language that was included in the R2 rationale,
but removed. The focus here is that we want to make sure the clock-hour average is still how we will be
measured and not individual AGC cycle contingency reserves calculations for carrying sufficient reserves.
3. In 1.3 its stated “deploy Contingency Reserve, within system constraints.“ We are not sure what is
meant by “system constraints” please clarify.

Thank you for the opportunity to comment on the draft BAL-002-2 standard. Western Area Power
Administration would like to provide the following comments:

Additional Comments Received from Steve Johnson – Western Area Power Administration

Standards Announcement Reminder
Project 2010-14.1 Phase 1 of Balancing Authority
Reliability-based Controls
BAL-002-2

Additional Ballot and Non-binding Poll Open through August 20, 2015
Now Available

An additional ballot for BAL-002-2 – Contingency Reserve for Recovery from Balancing Contingency
Event and a non-binding poll of the associated Violation Risk Factors and Violation Severity Levels are
open through 8 p.m. Eastern, Thursday, August 20, 2015.
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 standard
and post it for an additional ballot. If the comments do not show the need for significant revisions, the
standard will proceed to a final ballot.
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 2010-14.1 Phase 1 of Balancing Authority
Reliability-based Controls: Reserves
BAL-002-2
Formal Comment Period Open through August 20, 2015
Ballot Pools Forming through August 5, 2015
Now Available

A 45-day formal comment period for BAL-002-2 – Contingency Reserve for Recovery from Balancing
Contingency Event is open through 8 p.m. Eastern, Thursday, August 20, 2015.
Commenting

Use the electronic form to submit comments on the standard. 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, Wednesday, August 5, 2015.
Since the ballot pools for this project are outdated, new ones are being formed in the Standards
Balloting & Commenting System (SBS). If you previously joined the ballot pools for BAL-002-2, you
must join these ballot pools to cast a vote. Previous BAL-002-2 ballot pool members will not be
carried over. Registered Ballot Body members in the SBS may join the ballot pools here.
Next Steps

An additional ballot for the standard and a non-binding poll of the associated Violation Risk Factors
and Violation Severity Levels will be conducted August 11-20, 2015.
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 2010-14.1 Phase 1 of Balancing Authority
Reliability-based Controls
BAL-002-2
Additional Ballot and Non-binding Poll Results
Now Available

An additional ballot for BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery
from a Balancing Contingency Event concluded at 8 p.m. Eastern, Thursday, August 20, 2015. A nonbinding poll of the associated Violation Risk Factors and Violation Severity Levels was extended an
additional day to reach quorum and concluded at 8 p.m. Eastern, Friday, August 21, 2015.
The standard received sufficient affirmative votes for approval and voting statistics are listed below. The
Ballot Results page provides a link to the detailed results for the ballots.
Ballot

Non-binding Poll

Quorum /Approval

Quorum/Supportive
Opinions

75.92% / 69.26%

79.42% / 69.28%

Background information for this project can be found on the project page.
Next Steps

The drafting team will consider all comments received during the formal comment period and, if
needed, make revisions to the standard and post it for an additional ballot. If the comments do not
show the need for significant revisions, the standard will proceed to a final ballot.
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

Index - NERC Balloting Tool

NERC Balloting Tool

Dashboard

Users

Ballots

Surveys

Legacy SBS
Login / Register

BALLOT RESULTS
Survey: View Survey Results
Ballot Name: 2010-14.1 Phase 1 of Balancing Authority Reliability-based Controls BAL-002-2 IN 1 ST
Voting Start Date: 8/11/2015 12:01:00 AM
Voting End Date: 8/20/2015 8:00:00 PM
Ballot Type: ST
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 227
Total Ballot Pool: 299
Quorum: 75.92
Weighted Segment Value: 69.26

Ballot
Pool

Segment
Weight

Affirmative
Votes

Affirmative
Fraction

Negative
Votes w/
Comment

Negative
Fraction
w/
Comment

Segment:
1

74

1

31

0.646

17

0.354

0

5

21

Segment:
2

9

0.9

4

0.4

5

0.5

0

0

0

Segment:
3

70

1

31

0.738

11

0.262

0

13

15

Segment:
4

25

1

10

0.769

3

0.231

0

9

3

Segment:
5

66

1

25

0.676

12

0.324

0

11

18

Segment:
6

44

1

18

0.75

6

0.25

0

6

14

0

0

0

0

0

1

0.1

0

0

0

Segment

Segment: 0
0
0
0
7
© 2015 - NERC Ver 1.3.5.11 Machine Name: ERODVSBSWB02
Segment:

2

0.2

1

https://sbs.nerc.net/BallotResults/Index/47[11/2/2015 3:51:27 PM]

0.1

Negative
Votes
w/o
Comment

Abstain

No
Vote

Index - NERC Balloting Tool

8
Segment:
9

2

0.1

1

0.1

0

0

0

0

1

Segment:
10

7

0.7

6

0.6

1

0.1

0

0

0

Totals:

299

6.9

127

4.779

56

2.121

0

44

72

BALLOT POOL MEMBERS
Show All
All

Segment

Search:

entries

Organization

Voter

Designated
Proxy

Search

Ballot

NERC
Memo

1

Ameren - Ameren
Services

Eric Scott

None

N/A

1

APS - Arizona Public
Service Co.

Michelle Amarantos

Negative

Comments
Submitted

1

Associated Electric
Cooperative, Inc.

Phil Hart

Negative

Comments
Submitted

1

Avista - Avista
Corporation

Bryan Cox

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

1

BC Hydro and Power
Authority

Patricia Robertson

Affirmative

N/A

1

Beaches Energy
Services

Don Cuevas

Abstain

N/A

1

Berkshire Hathaway
Energy - MidAmerican

Terry Harbour

Affirmative

N/A

https://sbs.nerc.net/BallotResults/Index/47[11/2/2015 3:51:27 PM]

Joe Tarantino

Index - NERC Balloting Tool

Energy Co.
1

Black Hills Corporation

Wes Wingen

None

N/A

1

Bonneville Power
Administration

Donald Watkins

Affirmative

N/A

1

Bryan Texas Utilities

John Fontenot

Affirmative

N/A

1

Central Electric Power
Cooperative (Missouri)

Michael Bax

Negative

Third-Party
Comments

1

Cleco Corporation

John Lindsey

None

N/A

1

Colorado Springs
Utilities

Shawna Speer

None

N/A

1

Con Ed - Consolidated
Edison Co. of New
York

Chris de Graffenried

Negative

Third-Party
Comments

1

Dominion - Dominion
Virginia Power

Larry Nash

Affirmative

N/A

1

Duke Energy

Doug Hils

Affirmative

N/A

1

Edison International Southern California
Edison Company

Steven Mavis

Affirmative

N/A

1

Empire District Electric
Co.

Ralph Meyer

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

Great Plains Energy Kansas City Power
and Light Co.

James McBee

None

N/A

1

Great River Energy

Gordon Pietsch

Negative

Third-Party
Comments

1

Hydro One Networks,
Inc.

Payam Farahbakhsh

None

N/A

https://sbs.nerc.net/BallotResults/Index/47[11/2/2015 3:51:27 PM]

Louis Guidry

Index - NERC Balloting Tool

1

Hydro-Qu?bec
TransEnergie

Martin Boisvert

Affirmative

N/A

1

IDACORP - Idaho
Power Company

Molly Devine

Affirmative

N/A

1

International
Transmission
Company Holdings
Corporation

Michael Moltane

None

N/A

1

KAMO Electric
Cooperative

Walter Kenyon

Negative

Third-Party
Comments

1

Lincoln Electric
System

Doug Bantam

None

N/A

1

Los Angeles
Department of Water
and Power

faranak sarbaz

Affirmative

N/A

1

Lower Colorado River
Authority

Teresa Cantwell

Abstain

N/A

1

M and A Electric
Power Cooperative

William Price

Negative

Third-Party
Comments

1

Manitoba Hydro

Mike Smith

Affirmative

N/A

1

MEAG Power

David Weekley

Affirmative

N/A

1

Muscatine Power and
Water

Andy Kurriger

None

N/A

1

N.W. Electric Power
Cooperative, Inc.

Mark Ramsey

Negative

Third-Party
Comments

1

National Grid USA

Michael Jones

Abstain

N/A

1

NB Power Corporation

Alan MacNaughton

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

https://sbs.nerc.net/BallotResults/Index/47[11/2/2015 3:51:27 PM]

Scott Miller

Index - NERC Balloting Tool

1

NiSource - Northern
Indiana Public Service
Co.

Julaine Dyke

Negative

Comments
Submitted

1

Northeast Missouri
Electric Power
Cooperative

Kevin White

Negative

Third-Party
Comments

1

NorthWestern Energy

Belinda Tierney

None

N/A

1

OGE Energy Oklahoma Gas and
Electric Co.

Terri Pyle

None

N/A

1

Ohio Valley Electric
Corporation

Scott Cunningham

None

N/A

1

Omaha Public Power
District

Doug Peterchuck

Abstain

N/A

1

OTP - Otter Tail
Power Company

Charles Wicklund

Negative

Third-Party
Comments

1

Peak Reliability

Jared Shakespeare

Negative

Comments
Submitted

1

PHI - Potomac Electric
Power Co.

David Thorne

Affirmative

N/A

1

Platte River Power
Authority

John Collins

None

N/A

1

PNM Resources Public Service
Company of New
Mexico

Laurie Williams

Affirmative

N/A

1

Portland General
Electric Co.

John Walker

Affirmative

N/A

1

PPL Electric Utilities
Corporation

Brenda Truhe

Negative

Third-Party
Comments

1

PSEG - Public Service
Electric and Gas Co.

Joseph Smith

Affirmative

N/A

1

Public Utility District
No. 1 of Snohomish
County

Long Duong

None

N/A

1

Public Utility District

Michiko Sell

None

N/A

https://sbs.nerc.net/BallotResults/Index/47[11/2/2015 3:51:27 PM]

Index - NERC Balloting Tool

No. 2 of Grant County,
Washington
1

Sacramento Municipal
Utility District

Tim Kelley

1

Salt River Project

1

Affirmative

N/A

Steven Cobb

None

N/A

Santee Cooper

Shawn Abrams

None

N/A

1

SCANA - South
Carolina Electric and
Gas Co.

Tom Hanzlik

Negative

Comments
Submitted

1

Seattle City Light

Pawel Krupa

Affirmative

N/A

1

Seminole Electric
Cooperative, Inc.

Mark Churilla

Affirmative

N/A

1

Sho-Me Power
Electric Cooperative

Denise Stevens

Negative

Third-Party
Comments

1

Southern Company Southern Company
Services, Inc.

Robert A. Schaffeld

None

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

None

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

None

N/A

1

United Illuminating Co.

Jonathan Appelbaum

Affirmative

N/A

1

Western Area Power
Administration

Steve Johnson

Affirmative

N/A

1

Xcel Energy, Inc.

Dean Schiro

Affirmative

N/A

2

BC Hydro and Power
Authority

Venkataramakrishnan
Vinnakota

Affirmative

N/A

https://sbs.nerc.net/BallotResults/Index/47[11/2/2015 3:51:27 PM]

Joe Tarantino

Bret Galbraith

Index - NERC Balloting Tool

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

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

Comments
Submitted

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

None

N/A

3

APS - Arizona Public
Service Co.

Jeri Freimuth

Negative

Comments
Submitted

3

Associated Electric
Cooperative, Inc.

Todd Bennett

Negative

Comments
Submitted

3

Austin Energy

Lisa Martin

Abstain

N/A

3

Avista - Avista
Corporation

Scott Kinney

Affirmative

N/A

3

BC Hydro and Power
Authority

Pat Harrington

Affirmative

N/A

3

Beaches Energy
Services

Steven Lancaster

Abstain

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

None

N/A

https://sbs.nerc.net/BallotResults/Index/47[11/2/2015 3:51:27 PM]

Kathleen
Goodman

Darnez
Gresham

Index - NERC Balloting Tool

3

City of Green Cove
Springs

Mark Schultz

Abstain

N/A

3

City of Leesburg

Chris Adkins

Abstain

N/A

3

City of Redding

Elizabeth Hadley

None

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

Abstain

N/A

3

Con Ed - Consolidated
Edison Co. of New
York

Peter Yost

Negative

Third-Party
Comments

3

Dominion - Dominion
Resources, Inc.

Connie Lowe

Affirmative

N/A

3

DTE Energy - Detroit
Edison Company

Kent Kujala

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

Abstain

N/A

3

Florida Power & Light

Summer Esquerre

None

N/A

3

Georgia System
Operations
Corporation

Scott McGough

Abstain

N/A

3

Grand River Dam
Authority

Jeff Wells

None

N/A

3

Great Plains Energy Kansas City Power

Jessica Tucker

None

N/A

https://sbs.nerc.net/BallotResults/Index/47[11/2/2015 3:51:27 PM]

Louis Guidry

Index - NERC Balloting Tool

and Light Co.
3

Great River Energy

Brian Glover

Negative

Third-Party
Comments

3

KAMO Electric
Cooperative

Ted Hilmes

None

N/A

3

Lakeland Electric

Mace Hunter

Abstain

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

Negative

Third-Party
Comments

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

Abstain

N/A

3

Nebraska Public
Power District

Tony Eddleman

Abstain

N/A

3

New York Power
Authority

David Rivera

Affirmative

N/A

3

NiSource - Northern
Indiana Public Service
Co.

Ramon Barany

Negative

Comments
Submitted

3

Northeast Missouri
Electric Power
Cooperative

Skyler Wiegmann

None

N/A

3

NW Electric Power
Cooperative, Inc.

John Stickley

Negative

Third-Party
Comments

3

OGE Energy Oklahoma Gas and
Electric Co.

Donald Hargrove

Abstain

N/A

https://sbs.nerc.net/BallotResults/Index/47[11/2/2015 3:51:27 PM]

Index - NERC Balloting Tool

3

PHI - Potomac Electric
Power Co.

Mark Yerger

Affirmative

N/A

3

Platte River Power
Authority

Jeff Landis

None

N/A

3

PNM Resources

Michael Mertz

Affirmative

N/A

3

Portland General
Electric Co.

Thomas Ward

Abstain

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

Affirmative

N/A

3

Sacramento Municipal
Utility District

Rachel Moore

Affirmative

N/A

3

Salt River Project

John Coggins

Affirmative

N/A

3

Santee Cooper

James Poston

None

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

Negative

Third-Party
Comments

3

Snohomish County
PUD No. 1

Mark Oens

Affirmative

N/A

3

Southern Company Alabama Power
Company

R. Scott Moore

None

N/A

3

Tacoma Public Utilities
(Tacoma, WA)

Marc Donaldson

Affirmative

N/A

3

Tallahassee Electric
(City of Tallahassee,

John Williams

Affirmative

N/A

https://sbs.nerc.net/BallotResults/Index/47[11/2/2015 3:51:27 PM]

Joe Tarantino

Index - NERC Balloting Tool

FL)
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

3

Turlock Irrigation
District

James Ramos

Affirmative

N/A

3

WEC Energy Group,
Inc.

James Keller

Negative

Third-Party
Comments

3

Westar Energy

Bo Jones

None

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

Abstain

N/A

4

City of New Smyrna
Beach Utilities
Commission

Tim Beyrle

Abstain

N/A

4

City of Redding

Nick Zettel

None

N/A

4

City of Winter Park

Mark Brown

None

N/A

4

CMS Energy Consumers Energy
Company

Julie Hegedus

Abstain

N/A

4

DTE Energy - Detroit
Edison Company

Daniel Herring

Affirmative

N/A

4

FirstEnergy - Ohio
Edison Company

Doug Hohlbaugh

Affirmative

N/A

4

Flathead Electric
Cooperative

Russ Schneider

Abstain

N/A

https://sbs.nerc.net/BallotResults/Index/47[11/2/2015 3:51:27 PM]

Mary Downey

Index - NERC Balloting Tool

4

Florida Municipal
Power Agency

Carol Chinn

Abstain

N/A

4

Fort Pierce Utilities
Authority

Thomas Parker

Abstain

N/A

4

Georgia System
Operations
Corporation

Guy Andrews

Abstain

N/A

4

Keys Energy Services

Stanley Rzad

Abstain

N/A

4

MGE Energy Madison Gas and
Electric Co.

Joseph DePoorter

Negative

Third-Party
Comments

4

Modesto Irrigation
District

Spencer Tacke

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

Affirmative

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

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

Negative

Third-Party
Comments

5

Ameren - Ameren
Missouri

Sam Dwyer

None

N/A

5

APS - Arizona Public
Service Co.

Stephanie Little

Negative

Comments
Submitted

5

Associated Electric
Cooperative, Inc.

Matthew Pacobit

Negative

Comments
Submitted

https://sbs.nerc.net/BallotResults/Index/47[11/2/2015 3:51:27 PM]

Joe Tarantino

Index - NERC Balloting Tool

5

Austin Energy

Jeanie Doty

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

Choctaw Generation
Limited Partnership,
LLLP

Rob Watson

None

N/A

5

City of Independence,
Power and Light
Department

Jim Nail

Affirmative

N/A

5

City of Redding

Paul Cummings

Mary Downey

None

N/A

5

Cleco Corporation

Stephanie Huffman

Louis Guidry

None

N/A

5

CMS Energy Consumers Energy
Company

David Greyerbiehl

Abstain

N/A

5

Colorado Springs
Utilities

Jeff Icke

None

N/A

5

Con Ed - Consolidated
Edison Co. of New
York

Brian O'Boyle

Negative

Third-Party
Comments

5

Dairyland Power
Cooperative

Tommy Drea

None

N/A

5

Dominion - Dominion
Resources, Inc.

Randi Heise

Affirmative

N/A

5

DTE Energy - Detroit
Edison Company

Jeffrey DePriest

Affirmative

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Dynegy Inc.

Dan Roethemeyer

Negative

Comments
Submitted

https://sbs.nerc.net/BallotResults/Index/47[11/2/2015 3:51:27 PM]

Index - NERC Balloting Tool

5

Edison International Southern California
Edison Company

Michael McSpadden

Affirmative

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

Abstain

N/A

5

Great Plains Energy Kansas City Power
and Light Co.

Harold Wyble

None

N/A

5

Great River Energy

Preston Walsh

Negative

Third-Party
Comments

5

Hydro-Qu?bec
Production

Roger Dufresne

Affirmative

N/A

5

JEA

John Babik

Affirmative

N/A

5

Lakeland Electric

Jim Howard

Abstain

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

Abstain

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

NaturEner USA, LLC

Jamie Lynn Bussin

Abstain

N/A

5

NB Power Corporation

Rob Vance

Negative

Comments
Submitted

https://sbs.nerc.net/BallotResults/Index/47[11/2/2015 3:51:27 PM]

Scott Miller

Index - NERC Balloting Tool

5

Nebraska Public
Power District

Don Schmit

Abstain

N/A

5

New York Power
Authority

Wayne Sipperly

Affirmative

N/A

5

NextEra Energy

Allen Schriver

None

N/A

5

NiSource - Northern
Indiana Public Service
Co.

Michael Melvin

Negative

Comments
Submitted

5

OGE Energy Oklahoma Gas and
Electric Co.

Leo Staples

None

N/A

5

Omaha Public Power
District

Mahmood Safi

Abstain

N/A

5

OTP - Otter Tail
Power Company

Cathy Fogale

Negative

Third-Party
Comments

5

Platte River Power
Authority

Tyson Archie

Affirmative

N/A

5

Portland General
Electric Co.

Matt Jastram

None

N/A

5

PowerSouth Energy
Cooperative

Tim Hattaway

None

N/A

5

PPL Electric Utilities
Corporation

Dan Wilson

Negative

Third-Party
Comments

5

PSEG - PSEG Fossil
LLC

Tim Kucey

None

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

None

N/A

5

Sacramento Municipal
Utility District

Susan Gill-Zobitz

Affirmative

N/A

https://sbs.nerc.net/BallotResults/Index/47[11/2/2015 3:51:27 PM]

Joe Tarantino

Index - NERC Balloting Tool

5

Salt River Project

Kevin Nielsen

Affirmative

N/A

5

Santee Cooper

Lewis Pierce

None

N/A

5

SCANA - South
Carolina Electric and
Gas Co.

Edward Magic

Negative

Comments
Submitted

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

None

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

None

N/A

5

U.S. Bureau of
Reclamation

Erika Doot

Abstain

N/A

5

Xcel Energy, Inc.

Mark Castagneri

Affirmative

N/A

6

Ameren - Ameren
Services

Robert Quinlivan

None

N/A

6

APS - Arizona Public
Service Co.

Kristie Cocco

Negative

Comments
Submitted

6

Associated Electric
Cooperative, Inc.

Brian Ackermann

Negative

Comments
Submitted

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

None

N/A

https://sbs.nerc.net/BallotResults/Index/47[11/2/2015 3:51:27 PM]

Mary Downey

Index - NERC Balloting Tool

6

Cleco Corporation

Robert Hirchak

6

Colorado Springs
Utilities

6

None

N/A

Shannon Fair

None

N/A

Con Ed - Consolidated
Edison Co. of New
York

Robert Winston

Negative

Third-Party
Comments

6

Dominion - Dominion
Resources, Inc.

Louis Slade

Affirmative

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

Abstain

N/A

6

Florida Municipal
Power Pool

Tom Reedy

None

N/A

6

Great Plains Energy Kansas City Power
and Light Co.

Chris Bridges

None

N/A

6

Great River Energy

Donna Stephenson

Negative

Third-Party
Comments

6

Lincoln Electric
System

Eric Ruskamp

Abstain

N/A

6

Lower Colorado River
Authority

Michael Shaw

Abstain

N/A

6

Luminant - Luminant
Energy

Brenda Hampton

Abstain

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

None

N/A

6

New York Power
Authority

Shivaz Chopra

Affirmative

N/A

https://sbs.nerc.net/BallotResults/Index/47[11/2/2015 3:51:27 PM]

Louis Guidry

Michael
Brytowski

Nick Braden

Index - NERC Balloting Tool

6

NextEra Energy Florida Power and
Light Co.

Silvia Mitchell

None

N/A

6

NiSource - Northern
Indiana Public Service
Co.

Joe O'Brien

Negative

Comments
Submitted

6

OGE Energy Oklahoma Gas and
Electric Co.

Jerry Nottnagel

Abstain

N/A

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

Third-Party
Comments

6

PSEG - PSEG Energy
Resources and Trade
LLC

Karla Jara

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

None

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

None

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Rick Applegate

Affirmative

N/A

6

Talen Energy
Marketing, LLC

Elizabeth Davis

None

N/A

https://sbs.nerc.net/BallotResults/Index/47[11/2/2015 3:51:27 PM]

John Hare

Joe Tarantino

Index - NERC Balloting Tool

6

TECO - Tampa
Electric Co.

Benjamin Smith

None

N/A

6

Tennessee Valley
Authority

Marjorie Parsons

Affirmative

N/A

6

Xcel Energy, Inc.

Peter Colussy

Affirmative

N/A

8

David Kiguel

David Kiguel

Negative

Comments
Submitted

8

Massachusetts
Attorney General

Frederick Plett

Affirmative

N/A

9

City of Vero Beach

Ginny Beigel

None

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

Negative

Comments
Submitted

10

Northeast Power
Coordinating Council

Guy V. Zito

Affirmative

N/A

10

ReliabilityFirst

Anthony Jablonski

Affirmative

N/A

10

SERC Reliability
Corporation

Joe Spencer

Affirmative

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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https://sbs.nerc.net/BallotResults/Index/47[11/2/2015 3:51:27 PM]

Index - NERC Balloting Tool

NERC Balloting Tool

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BALLOT RESULTS
Ballot Name: 2010-14.1 Phase 1 of Balancing Authority Reliability-based Controls BAL-002-2 Non-binding Poll IN 1 NB
Voting Start Date: 8/11/2015 12:01:00 AM
Voting End Date: 8/21/2015 8:00:00 PM
Ballot Type: NB
Ballot Activity: IN
Ballot Series: 1
Total # Votes: 220
Total Ballot Pool: 277
Quorum: 79.42
Weighted Segment Value: 69.28

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

69

1

24

0.632

14

0.368

0

11

20

Segment:
2

9

0.6

3

0.3

3

0.3

0

3

0

Segment:
3

66

1

25

0.694

11

0.306

0

21

9

Segment:
4

21

1

10

0.909

1

0.091

0

8

2

Segment:
5

60

1

23

0.676

11

0.324

0

12

14

Segment:
6

41

1

13

0.684

6

0.316

0

11

11

Segment:
7

0

0

0

0

0

0

0

0

0

1

0.1

0

0

0

Segment

© 2015
- NERC Ver
ERODVSBSWB01
Segment:
2 1.3.5.11
0.2Machine Name:
1
0.1
8

https://sbs.nerc.net/BallotResults/Index/48[11/2/2015 3:52:49 PM]

Index - NERC Balloting Tool

Segment:
9

2

0.1

1

0.1

0

0

0

0

1

Segment:
10

7

0.6

6

0.6

0

0

0

1

0

Totals:

277

6.5

106

4.695

47

1.805

0

67

57

BALLOT POOL MEMBERS
Show All
All

Segment

Search:

entries

Organization

Voter

Designated
Proxy

Search

Ballot

NERC
Memo

1

Ameren - Ameren
Services

Eric Scott

None

N/A

1

APS - Arizona Public
Service Co.

Michelle Amarantos

Negative

Comments
Submitted

1

Associated Electric
Cooperative, Inc.

Phil Hart

Negative

Comments
Submitted

1

Avista - Avista
Corporation

Bryan Cox

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

1

BC Hydro and Power
Authority

Patricia Robertson

Abstain

N/A

1

Beaches Energy
Services

Don Cuevas

Abstain

N/A

1

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Terry Harbour

Affirmative

N/A

https://sbs.nerc.net/BallotResults/Index/48[11/2/2015 3:52:49 PM]

Joe Tarantino

Index - NERC Balloting Tool

1

Bonneville Power
Administration

Donald Watkins

Affirmative

N/A

1

Bryan Texas Utilities

John Fontenot

Affirmative

N/A

1

Central Electric Power
Cooperative (Missouri)

Michael Bax

Negative

Comments
Submitted

1

Cleco Corporation

John Lindsey

None

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

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

Empire District Electric
Co.

Ralph Meyer

None

N/A

1

Entergy - Entergy
Services, Inc.

Oliver Burke

Affirmative

N/A

1

FirstEnergy FirstEnergy
Corporation

William Smith

Affirmative

N/A

1

Great Plains Energy Kansas City Power
and Light Co.

James McBee

None

N/A

1

Great River Energy

Gordon Pietsch

Negative

Comments
Submitted

1

Hydro One Networks,
Inc.

Payam Farahbakhsh

None

N/A

1

Hydro-Qu?bec
TransEnergie

Martin Boisvert

Affirmative

N/A

1

IDACORP - Idaho
Power Company

Molly Devine

Affirmative

N/A

https://sbs.nerc.net/BallotResults/Index/48[11/2/2015 3:52:49 PM]

Louis Guidry

Index - NERC Balloting Tool

1

International
Transmission
Company Holdings
Corporation

Michael Moltane

Abstain

N/A

1

KAMO Electric
Cooperative

Walter Kenyon

Negative

Comments
Submitted

1

Lincoln Electric
System

Doug Bantam

None

N/A

1

Los Angeles
Department of Water
and Power

faranak sarbaz

Affirmative

N/A

1

Lower Colorado River
Authority

Teresa Cantwell

Abstain

N/A

1

M and A Electric
Power Cooperative

William Price

Negative

Comments
Submitted

1

Manitoba Hydro

Mike Smith

Affirmative

N/A

1

MEAG Power

David Weekley

Affirmative

N/A

1

Muscatine Power and
Water

Andy Kurriger

None

N/A

1

N.W. Electric Power
Cooperative, Inc.

Mark Ramsey

Negative

Comments
Submitted

1

National Grid USA

Michael Jones

Abstain

N/A

1

Nebraska Public
Power District

Jamison Cawley

Abstain

N/A

1

New York Power
Authority

Salvatore Spagnolo

Affirmative

N/A

1

NextEra Energy Florida Power and
Light Co.

Mike ONeil

Negative

Comments
Submitted

1

NiSource - Northern
Indiana Public Service
Co.

Julaine Dyke

Negative

Comments
Submitted

1

Northeast Missouri
Electric Power
Cooperative

Kevin White

Negative

Comments
Submitted

1

NorthWestern Energy

Belinda Tierney

None

N/A

https://sbs.nerc.net/BallotResults/Index/48[11/2/2015 3:52:49 PM]

Scott Miller

Index - NERC Balloting Tool

1

OGE Energy Oklahoma Gas and
Electric Co.

Terri Pyle

None

N/A

1

Ohio Valley Electric
Corporation

Scott Cunningham

None

N/A

1

Omaha Public Power
District

Doug Peterchuck

Abstain

N/A

1

Peak Reliability

Jared Shakespeare

Negative

Comments
Submitted

1

Platte River Power
Authority

John Collins

None

N/A

1

PNM Resources Public Service
Company of New
Mexico

Laurie Williams

Affirmative

N/A

1

Portland General
Electric Co.

John Walker

Affirmative

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

None

N/A

1

Public Utility District
No. 2 of Grant County,
Washington

Michiko Sell

None

N/A

1

Sacramento Municipal
Utility District

Tim Kelley

Affirmative

N/A

1

Salt River Project

Steven Cobb

None

N/A

1

Santee Cooper

Shawn Abrams

Abstain

N/A

1

SCANA - South
Carolina Electric and
Gas Co.

Tom Hanzlik

Negative

Comments
Submitted

1

Seattle City Light

Pawel Krupa

Affirmative

N/A

https://sbs.nerc.net/BallotResults/Index/48[11/2/2015 3:52:49 PM]

Joe Tarantino

Index - NERC Balloting Tool

1

Seminole Electric
Cooperative, Inc.

Mark Churilla

1

Sho-Me Power Electric
Cooperative

1

Affirmative

N/A

Denise Stevens

Negative

Comments
Submitted

Southern Company Southern Company
Services, Inc.

Robert A. Schaffeld

Affirmative

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

Abstain

N/A

1

Tri-State G and T
Association, Inc.

Tracy Sliman

None

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

None

N/A

1

United Illuminating Co.

Jonathan Appelbaum

Affirmative

N/A

1

Western Area Power
Administration

Steve Johnson

None

N/A

1

Xcel Energy, Inc.

Dean Schiro

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

Affirmative

N/A

2

Independent Electricity
System Operator

Leonard Kula

Affirmative

N/A

2

ISO New England, Inc.

Michael Puscas

Abstain

N/A

2

Midcontinent ISO, Inc.

Terry BIlke

Negative

Comments

https://sbs.nerc.net/BallotResults/Index/48[11/2/2015 3:52:49 PM]

Bret Galbraith

Kathleen
Goodman

Index - NERC Balloting Tool

Submitted
2

PJM Interconnection,
L.L.C.

Mark Holman

Affirmative

N/A

2

Southwest Power
Pool, Inc. (RTO)

Charles Yeung

Abstain

N/A

3

Ameren - Ameren
Services

David Jendras

None

N/A

3

APS - Arizona Public
Service Co.

Jeri Freimuth

Negative

Comments
Submitted

3

Associated Electric
Cooperative, Inc.

Todd Bennett

Negative

Comments
Submitted

3

Austin Energy

Lisa Martin

Abstain

N/A

3

Avista - Avista
Corporation

Scott Kinney

Affirmative

N/A

3

BC Hydro and Power
Authority

Pat Harrington

Abstain

N/A

3

Beaches Energy
Services

Steven Lancaster

Abstain

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

Negative

Comments
Submitted

3

City of Green Cove
Springs

Mark Schultz

Abstain

N/A

3

City of Leesburg

Chris Adkins

Abstain

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

Abstain

N/A

3

Con Ed - Consolidated

Peter Yost

Negative

Comments

https://sbs.nerc.net/BallotResults/Index/48[11/2/2015 3:52:49 PM]

Darnez
Gresham

Louis Guidry

Index - NERC Balloting Tool

Edison Co. of New
York

Submitted

3

Dominion - Dominion
Resources, Inc.

Connie Lowe

Abstain

N/A

3

DTE Energy - Detroit
Edison Company

Kent Kujala

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

Abstain

N/A

3

Florida Power & Light

Summer Esquerre

None

N/A

3

Georgia System
Operations
Corporation

Scott McGough

Abstain

N/A

3

Grand River Dam
Authority

Jeff Wells

Affirmative

N/A

3

Great Plains Energy Kansas City Power
and Light Co.

Jessica Tucker

None

N/A

3

Great River Energy

Brian Glover

Negative

Comments
Submitted

3

KAMO Electric
Cooperative

Ted Hilmes

Negative

Comments
Submitted

3

Lakeland Electric

Mace Hunter

Abstain

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

Negative

Comments
Submitted

https://sbs.nerc.net/BallotResults/Index/48[11/2/2015 3:52:49 PM]

Index - NERC Balloting Tool

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

Comments
Submitted

3

National Grid USA

Brian Shanahan

Abstain

N/A

3

Nebraska Public
Power District

Tony Eddleman

Abstain

N/A

3

New York Power
Authority

David Rivera

Affirmative

N/A

3

NiSource - Northern
Indiana Public Service
Co.

Ramon Barany

Negative

Comments
Submitted

3

Northeast Missouri
Electric Power
Cooperative

Skyler Wiegmann

None

N/A

3

NW Electric Power
Cooperative, Inc.

John Stickley

Negative

Comments
Submitted

3

OGE Energy Oklahoma Gas and
Electric Co.

Donald Hargrove

Abstain

N/A

3

Platte River Power
Authority

Terry Baker

Affirmative

N/A

3

PNM Resources

Michael Mertz

Affirmative

N/A

3

Portland General
Electric Co.

Thomas Ward

Abstain

N/A

3

PPL - Louisville Gas
and Electric Co.

Charles Freibert

None

N/A

3

PSEG - Public Service
Electric and Gas Co.

Jeffrey Mueller

Abstain

N/A

3

Public Utility District
No. 1 of Okanogan
County

Dale Dunckel

None

N/A

https://sbs.nerc.net/BallotResults/Index/48[11/2/2015 3:52:49 PM]

Index - NERC Balloting Tool

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

Affirmative

N/A

3

Santee Cooper

James Poston

Abstain

N/A

3

Seattle City Light

Dana Wheelock

Abstain

N/A

3

Seminole Electric
Cooperative, Inc.

James Frauen

Affirmative

N/A

3

Sho-Me Power Electric
Cooperative

Jeff Neas

Negative

Comments
Submitted

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

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

Affirmative

N/A

3

Turlock Irrigation
District

James Ramos

Affirmative

N/A

3

Westar Energy

Bo Jones

None

N/A

3

Xcel Energy, Inc.

Michael Ibold

Abstain

N/A

4

Alliant Energy
Corporation Services,
Inc.

Kenneth Goldsmith

Affirmative

N/A

https://sbs.nerc.net/BallotResults/Index/48[11/2/2015 3:52:49 PM]

Joe Tarantino

Index - NERC Balloting Tool

4

Austin Energy

Tina Garvey

Abstain

N/A

4

Blue Ridge Power
Agency

Duane Dahlquist

Affirmative

N/A

4

City of Clewiston

Lynne Mila

Abstain

N/A

4

City of New Smyrna
Beach Utilities
Commission

Tim Beyrle

Abstain

N/A

4

City of Winter Park

Mark Brown

None

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

Abstain

N/A

4

Fort Pierce Utilities
Authority

Thomas Parker

Abstain

N/A

4

Georgia System
Operations
Corporation

Guy Andrews

Abstain

N/A

4

Keys Energy Services

Stanley Rzad

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

Affirmative

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

Tacoma Public Utilities

Hien Ho

Affirmative

N/A

https://sbs.nerc.net/BallotResults/Index/48[11/2/2015 3:52:49 PM]

Joe Tarantino

Index - NERC Balloting Tool

(Tacoma, WA)
4

Utility Services, Inc.

Brian Evans-Mongeon

Abstain

N/A

4

WEC Energy Group,
Inc.

Anthony Jankowski

Negative

Comments
Submitted

5

Ameren - Ameren
Missouri

Sam Dwyer

None

N/A

5

APS - Arizona Public
Service Co.

Stephanie Little

Negative

Comments
Submitted

5

Associated Electric
Cooperative, Inc.

Matthew Pacobit

Negative

Comments
Submitted

5

Austin Energy

Jeanie Doty

Abstain

N/A

5

BC Hydro and Power
Authority

Clement Ma

Abstain

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

Comments
Submitted

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

None

N/A

5

CMS Energy Consumers Energy
Company

David Greyerbiehl

Abstain

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

https://sbs.nerc.net/BallotResults/Index/48[11/2/2015 3:52:49 PM]

Louis Guidry

Index - NERC Balloting Tool

5

Dairyland Power
Cooperative

Tommy Drea

None

N/A

5

Dominion - Dominion
Resources, Inc.

Randi Heise

None

N/A

5

DTE Energy - Detroit
Edison Company

Jeffrey DePriest

Abstain

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Dynegy Inc.

Dan Roethemeyer

Negative

Comments
Submitted

5

Edison International Southern California
Edison Company

Michael McSpadden

Affirmative

N/A

5

FirstEnergy FirstEnergy Solutions

Robert Loy

Affirmative

N/A

5

Florida Municipal
Power Agency

David Schumann

Abstain

N/A

5

Great Plains Energy Kansas City Power
and Light Co.

Harold Wyble

None

N/A

5

Great River Energy

Preston Walsh

Negative

Comments
Submitted

5

Hydro-Qu?bec
Production

Roger Dufresne

Affirmative

N/A

5

JEA

John Babik

Affirmative

N/A

5

Lakeland Electric

Jim Howard

Abstain

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

Manitoba Hydro

Yuguang Xiao

Affirmative

N/A

5

Massachusetts
Municipal Wholesale

David Gordon

Abstain

N/A

https://sbs.nerc.net/BallotResults/Index/48[11/2/2015 3:52:49 PM]

Index - NERC Balloting Tool

Electric Company
5

MEAG Power

Steven Grego

5

Muscatine Power and
Water

5

Affirmative

N/A

Mike Avesing

Negative

Comments
Submitted

NaturEner USA, LLC

Jamie Lynn Bussin

Affirmative

N/A

5

Nebraska Public
Power District

Don Schmit

Abstain

N/A

5

New York Power
Authority

Wayne Sipperly

Affirmative

N/A

5

NextEra Energy

Allen Schriver

Negative

Comments
Submitted

5

NiSource - Northern
Indiana Public Service
Co.

Michael Melvin

Negative

Comments
Submitted

5

OGE Energy Oklahoma Gas and
Electric Co.

Leo Staples

None

N/A

5

Omaha Public Power
District

Mahmood Safi

Abstain

N/A

5

Portland General
Electric Co.

Matt Jastram

None

N/A

5

PowerSouth Energy
Cooperative

Tim Hattaway

None

N/A

5

PPL Electric Utilities
Corporation

Dan Wilson

Negative

Comments
Submitted

5

PSEG - PSEG Fossil
LLC

Tim Kucey

None

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

None

N/A

https://sbs.nerc.net/BallotResults/Index/48[11/2/2015 3:52:49 PM]

Scott Miller

Index - NERC Balloting Tool

5

Sacramento Municipal
Utility District

Susan Gill-Zobitz

5

Salt River Project

5

Affirmative

N/A

Kevin Nielsen

Affirmative

N/A

Santee Cooper

Lewis Pierce

None

N/A

5

SCANA - South
Carolina Electric and
Gas Co.

Edward Magic

Negative

Comments
Submitted

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

TECO - Tampa
Electric Co.

R James Rocha

None

N/A

5

Tennessee Valley
Authority

Brandy Spraker

Affirmative

N/A

5

U.S. Bureau of
Reclamation

Erika Doot

Abstain

N/A

5

Xcel Energy, Inc.

David Lemmons

None

N/A

6

Ameren - Ameren
Services

Robert Quinlivan

None

N/A

6

APS - Arizona Public
Service Co.

Kristie Cocco

Negative

Comments
Submitted

6

Associated Electric
Cooperative, Inc.

Brian Ackermann

Negative

Comments
Submitted

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

https://sbs.nerc.net/BallotResults/Index/48[11/2/2015 3:52:49 PM]

Joe Tarantino

Index - NERC Balloting Tool

6

Cleco Corporation

Robert Hirchak

6

Colorado Springs
Utilities

6

None

N/A

Shannon Fair

None

N/A

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

Abstain

N/A

6

Florida Municipal
Power Pool

Tom Reedy

Abstain

N/A

6

Great Plains Energy Kansas City Power
and Light Co.

Chris Bridges

None

N/A

6

Great River Energy

Donna Stephenson

Negative

Comments
Submitted

6

Lincoln Electric
System

Eric Ruskamp

Abstain

N/A

6

Lower Colorado River
Authority

Michael Shaw

Abstain

N/A

6

Luminant - Luminant
Energy

Brenda Hampton

Abstain

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

None

N/A

6

New York Power
Authority

Shivaz Chopra

Affirmative

N/A

6

NextEra Energy Florida Power and
Light Co.

Silvia Mitchell

None

N/A

6

NiSource - Northern

Joe O'Brien

Negative

Comments

https://sbs.nerc.net/BallotResults/Index/48[11/2/2015 3:52:49 PM]

Louis Guidry

Michael
Brytowski

Nick Braden

Index - NERC Balloting Tool

Indiana Public Service
Co.

Submitted

6

OGE Energy Oklahoma Gas and
Electric Co.

Jerry Nottnagel

6

Platte River Power
Authority

6

Abstain

N/A

Carol Ballantine

Abstain

N/A

Portland General
Electric Co.

Shawn Davis

None

N/A

6

PPL - Louisville Gas
and Electric Co.

OELKER LINN

None

N/A

6

PSEG - PSEG Energy
Resources and Trade
LLC

Karla Jara

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

Abstain

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

Affirmative

N/A

6

Tacoma Public Utilities
(Tacoma, WA)

Rick Applegate

Affirmative

N/A

6

Talen Energy
Marketing, LLC

Elizabeth Davis

None

N/A

6

TECO - Tampa
Electric Co.

Benjamin Smith

None

N/A

6

Tennessee Valley
Authority

Marjorie Parsons

Abstain

N/A

https://sbs.nerc.net/BallotResults/Index/48[11/2/2015 3:52:49 PM]

John Hare

Joe Tarantino

Index - NERC Balloting Tool

6

WEC Energy Group,
Inc.

David Hathaway

Negative

Comments
Submitted

8

David Kiguel

David Kiguel

Negative

Comments
Submitted

8

Massachusetts
Attorney General

Frederick Plett

Affirmative

N/A

9

City of Vero Beach

Ginny Beigel

None

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

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

Joe Spencer

Affirmative

N/A

10

Texas Reliability
Entity, Inc.

Rachel Coyne

Affirmative

N/A

10

Western Electricity
Coordinating Council

Steven Rueckert

Abstain

N/A

Previous
Showing 1 to 277 of 277 entries

https://sbs.nerc.net/BallotResults/Index/48[11/2/2015 3:52:49 PM]

1

Next

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 33 sets of responses, including comments from approximately 87 different people from approximately 63 different
companies representing 8 of the 10 Industry Segments as shown on the following pages.

Associated Ballot: 2010-14.1 Phase 1 of Balancing Authority Reliability-based Controls BAL-002-2 IN 1 ST

Comment Period End Date: 8/20/2015

Comment Period Start Date: 7/7/2015

Project Name: 2010-14.1 Phase 1 of Balancing Authority Reliability-based Controls | BAL-002-2

Consideration of Comments

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Answer Comment:

Dan Roethemeyer - Dynegy Inc. - 5 -

2

Our entity, as a Generation only BA, currently under BAL-002-1 uses
“Coordinated adjustments to interchange schedules” as the primary method
of meeting the standard. The new standard BAL-002-2 Rev 7 is not clear if
“Coordinated adjustments to interchange schedules” will be allowed. We feel
the language needs to be clarified as to what is allowed as contingency

1. Please provide any issues you have on this draft of the BAL-002-2 standard and offer a proposed solution for those issues.

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:

1. Please provide any issues you have on this draft of the BAL-002-2 standard and offer a proposed solution for those issues.

Questions

No Comment just want to vote Yes

No issues

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

John Fontenot - Bryan Texas Utilities - 1 -

Response: The SDT thanks you for your affirmative response.

Answer Comment:

Nick Vtyurin - Manitoba Hydro - 1,3,5,6 – MRO

Response: The SDT thanks you for your affirmative response.

Answer Comment:

Alex Ybarra - Public Utility District No. 2 of Grant County, Washington - 5 –

Response:

3

reserve since “The provision of capacity that may be deployed by Balancing
Authority” is vague.
As drafted, the standard states the requirement, not how to meet the
requirement. The proposed language tells how to meet the requirement. As
drafted, the standard does not prohibit any adjustments that correct ACE.

none

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Tony Eddleman

Group Member Name
Joe Depoorter
Amy Casucelli
Chuck Lawrence
Chuck Wicklund
Theresa Allard
Dave Rudolph
Kayleigh Wilkerson
Jodi Jenson
Larry Heckert
Mahmood Safi
Marie Knox
Mike Brytowski
Randi Nyholm
Scott Nickels
Terry Harbour
Tom Breene

Group Name:

Emily Rousseau - MRO - 1,2,3,4,5,6 – MRO

Entity
Madison Gas & Electric
Xcel Energy
American Transmission Company
Otter Tail Power Company
Minnkota Power Cooperative, Inc
Basin Electric Power Cooperative
Lincoln Electric System
Western Area Power Administration
Alliant Energy
Omaha Public Utility District
Midwest ISO Inc.
Great River Energy
Minnesota Power
Rochester Public Utilities
MidAmerican Energy Company
Wisconsin Public Service
Corporation
Nebraska Public Power District

MRO-NERC Standards Review Forum (NSRF)

Response: The SDT thanks you for your affirmative response.

Answer Comment:

MRO

Region
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO
MRO

1,3,5

Segments
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
1,3,5,6
2
1,3,5,6
1,5
4
1,3,5,6
3,4,5,6

4

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Answer Comment:

5

The standard should retain a simple quarterly report form rather than
creating forms for each report. The reasoning the drafting team gave for not
adopting this recommendation is not substantiated. It just says that VSLs for
small entities will be Severe without providing examples. Performance is
performance. Size has no impact in this standard. VSLs are just a starting
point in the enforcement process. Regional enforcement staff will determine
the seriousness and risk associated with a violation. We can provide a simple
example of a form that would work for this standard. It would keep
reporting simple and provide NERC the data it needs for its State of Reliability
Report.
R1 part 1.2 does not require a report to be submitted. Instead it requires the
calculation to be on the referenced form. This ensures all entities subject to
compliance utilize the same methodology for each event. The SDT disagrees
with the inclusion of a quarterly report in a standard. If NERC or the Regions
desire quarterly reporting it should be done under their data collection
process.
While not primary concerns, the standard could be clearer if the following
changes were made:

R1.1.2, reporting events should be covered in the compliance section of the
standard, not a requirement. Please refer to NERC’s paragraph 81 criteria
“B4 Reporting”, which notes that documentation should not be included in a
standard as a requirement.

Our primary concerns are the following:

We appreciate that the drafting team has removed the zero defect
component of the standard and that the current draft acknowledges that
reserves should be deployed to address multiple reliability issues.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

6

For the definition of Contingency Event Recovery Period, since small events
can happen in sequence (such as runbacks or individual generator trips on a
combined cycle plant), the recovery period should not start with the initial
decline as the BA may not know they are in a DCS event until the event has
played out. Recommend changing the wording be changed to "begins at the
time when ACE reaches the reportable threshold of a Balancing Contingency
Event, and extends for fifteen minutes”
There is not an ACE threshold for a reportable event. The reportable event is
established by the amount of the resource loss. For the purposes of a
runback, if the MW threshold is not reached in a single minute then it would
not be considered a reportable event. Therefore, the start of the event

Most Severe Single Contingency (MSSC): The Balancing Contingency Event,
due to a single contingency as identified and maintained in the system
models within the Reserve Sharing Group (RSG) or a Balancing Authority’s
area that is not part of a Reserve Sharing Group, that would result in the
greatest loss (measured in MW) of resource output used by the RSG or a
Balancing Authority.
Some RSGs allow for members to participate in the group on an event-byevent basis. The additional language allows for this flexibility.

The last two and a half lines of the MSSC definition are unnecessary. The
definition can be:

Under the term for a Balancing Contingency Event, a change in ACE is only
mentioned for the loss of generation, not the other resource losses. It’s
probably not necessary to mention change in ACE as a resource loss is a
resource loss.
The SDT believes that a change in ACE is in the appropriate location in the
definition. The SDT agrees with you that a resource loss is a resource loss.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Answer Comment:
As a stakeholder of MISO, we are supporting their comments.

7

MRO supports the intent of BAL-002-2 however, MRO does not support the
addition of R1.2. R1.2 is purely adminstrative in nature and reporting
should not be part of a reliability Standard.
R1 part 1.2 does not require a report to be submitted. Instead it requires the
calculation to be on the referenced form. This ensures all entities subject to
compliance utilize the same methodology for each event. The SDT agrees
that reporting should not be part of a standard.

Joe O'Brien - NiSource - Northern Indiana Public Service Co. - 6 –

Response:

Answer Comment:

Russel Mountjoy - Midwest Reliability Organization - 10 -

Response:

We can provide a redline of the standard that has minor housekeeping edits
that would simplify wording upon request.

would be the minute in which the threshold is met not the start of the
runback.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Answer Comment:

Terry BIlke - Midcontinent ISO, Inc. - 2 –

Response:

8

ͻThe Paragraph 81 criteria note that reporting and filling out paperwork
should not be a requirement, yet there is such a requirement to “document
all Reportable Balancing Contingency Events using CR Form 1”. Rather than a
requirement, this should be explained in the compliance section of the
standard.
The SDT disagrees with the characterization that this is a Paragraph 81 issue.
The Requirement R1 part 1.2 requires a specific calculation in the form. This
ensures all entities subject to compliance utilize the same methodology for
each event. There is not a reporting requirement in the standard.

ͻR2 is ambiguous as to what is meant by “review and maintain annually,
and implement”. While it looked like the drafting team moved away from a
zero defect standard (where reserves must be > MSSC every hour), the RSAW
implies that the ERO interprets this wording differently. The drafting team’s
intent should be clear in the measure that operators should not be
discouraged to deploy reserves when needed, but they do need an approach
to be notified when reserves are low and a means to replenish them.
The SDT agrees that the RSAW could be interpreted in such a manner to not
meet the intent of the requirement. The RSAW is being modified to clarify
the necessary compliance elements for the next posting.

We have three primary concerns with this standard:

Please refer to the SDT response to the comments submitted by MISO.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Response:

9

We had additional comments that would make the standard simpler or
clearer. These have been previously sent to the drafting team.

As the current standard is structured, it looks like it will cause BAs to
request EEAs whenever reserves are reduced to address day to day balancing
issues. Even though there is no change in reliability, the likely step increase
in EEAs will likely trigger other concerns, the solution for which would likely
be another standard. The standard should be clearer in the measure and
supporting information that reserves can be drawn down, but the BA needs
an approach to replenish them or call EEAs if unable to do so.
The SDT is unsure as to what is meant by your comment. There is no
requirement in the proposed standard for reserves to be held on a real-time
basis, addressing an issue of contention within the current standard. Instead
there are requirements addressing correction of ACE, to plan for reserves on
a day-ahead basis, and to restore reserve following a Reportable Balancing
Contingency Event.

ͻWe do not agree with the move away from simple quarterly
reporting. While there is stray wording in Order No. 693 on compliance for
single events, this does not preclude submitting a quarterly report. As it is,
NERC will likely still request this data for “State of Reliability Reporting” and
then auditors will ask to see the reports again as well.
The SDT disagrees with the inclusion of a quarterly report in a standard.
Adding a requirement for quarterly reporting would be a Paragraph 81 issue.
If NERC or the Regions desire quarterly reporting it should be done under
their data collection process.

Hydro-Quebec TransEnergie supports NPCC comments.
Please refer to our response to the comments submitted by NPCC.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Answer Comment:

10

As an illustration, failing R1 except under certain conditions which include
the Contingency Reserve Restoration period implies that a BA didn’t have

However, we are still unable to find the need and reliability benefit of R3
which requires a BA to restore its Contingency Reserve to at least its Most
Severe Single Contingency (MSSC) before the end of the Contingency
Reserve Restoration Period given the need to meet R1 except under the
specified conditions which include events occurring during Contingency
Reserve Restoration Period. By virtue of meeting R1, a BA must have
Contingency Reserve that equals or exceeds MSSC at all time (expect under
the conditions in Part 1.3). Replenishing Contingency Reserve is thus an
implicit requirement in R1. Having an explicit requirement for replenishing
reserve in R3 will expose Responsible Entities to potential double jeopardy,
is unnecessary and adds no reliability value.

The IESO thanks the SDT for revising the previous R2 to remove those parts
that contain confusing language and are deemed unnecessary.

Leonard Kula - Independent Electricity System Operator - 2 -

Response:

Answer Comment:

Si Truc Phan - Hydro-Qu?bec TransEnergie - 1 – NPCC

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Answer Comment:

Rob Vance - NB Power Corporation - 5 -

Response:

11

We also submitted our comments through NPCC. We feel the intent of the
3rd bullet of Requirement 1.3.1 is to ensure that all required reserve up to
the MSSC required reserve value is used prior to the waiver of Requirement

We therefore once again propose that R3 be removed.
While the SDT appreciates your position, we believe that R3 is significantly
different than R1. R1 requires an entity to recover from an event within a 15
minute window. R3 requires an entity to essentially modify their day-ahead
plan to address the circumstance in the real-time and to address the next
contingency if it were to occur. There is no expectation to carry reserves
during the Contingency Reserve Restoration Period. Additionally,
Requirement R3 carries forward the intent of the current BAL-002-1
Requirement R6.

Having only R1 would suffice as this requirement will drive a BA to recover
or have sufficient CR except under certain conditions.

sufficient contingency reserve to meet the ACE recovery requirement
stipulated in R1. Failing R3 means a BA did not restore (or have) sufficient
contingency reserve except during the Contingency Reserve Restoration
period. Note that an event may or may not occur at a time when a BA does
not have sufficient CR, so a BA may fail R3 alone but not R1. However, the
reverse is not true. A BA that fails R1 will most likely (if not invariably) also
fails R3, hence the double jeopardy.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

12

Also, we feel the same R1.1 waiver should apply for multiple contingencies
that use all of the required reserve regardless of whether a declared Energy
Emergency Alert is in effect. An EEA is used only if there are already
insufficient reserves to meet requirements or an expectation of not
meeting requirements. In the case of a non-emergency normal restoration
that doesn't require a declared emercy but becomes difficult near the end of
the Contingency Event Recovery Period, the time it takes to declare an
emergency may extend the actual recovery beyond the Contingency Event
Recovery Period thereby creating a non-compliance. The exemption in the
current BAL-002-1 standard (see section 1.5 of part D of the standard) does
not require a previously declared emergency. If necessary, a declaration of an
Energy Emergency Alert can be made ASAP after a restoration has failed to
meet the Contingency Event Recovery Period requirement.
The SDT agrees with your premise. Please refer to Requirement R1 Part 1.3.2
where the SDT excluded multiple events which exceeds MSSC.

1.1 becoming available. The current wording suggests that you need only
deplete reserves to a value less than the MSSC required reserve amount and
the waiver will be enabled. This would wave the normal requirement to
restore ACE even while leftover reserve is still available. We feel the wording
"the Responsible Entity has depleted its Contingency Reserve to a level below
its Most Severe Single Contingency" should be changed to read "the
Responsible Entity has depleted its Contingency Reserve by at least the
amount of reserve required for its Most Severe Single Contingency".
The SDT disagrees with your view because all of the three bullets must be
met not just the third bullet. In addition, the bullets in R1 part 1.3 are listing
the system condition at the time of the Reportable Balancing Contingency
Event not following the Reportable Balancing Contingency Event. As an
example, if you are not in the EEA prior to the loss, the waiver would not
apply.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Answer Comment:

David Kiguel - David Kiguel - 8 –

Response:

13

3. Requirement R3 seems to contain obligations that are related to/repeated

2. Sub-Requirement R1.2 refers to documentation and as such is
administrative in nature, i.e. does not contribute to Reliability. Furthermore,
it seems to meet Criterion B4 of the Paragraph 81 Criteria.
The SDT disagrees with the characterization that this is a Paragraph 81 issue.
The Requirement R1 part 1.2 requires a specific calculation in the form. This
ensures all entities subject to compliance utilize the same methodology for
each event. There is not a reporting requirement in the standard.

1. R1.3 is confusing. Instead of detailing what the Responsible Entity must
do, it extends to details on what is NOT subject to compliance. Results
based standards must focus on what reliability objectives are to be achieved
rather than what is not subject to compliance. All after “however, it is not
subject to compliance with Requirement 1, part 1.1….” does not belong in
the requirement. It could be part of the Compliance Section.
While the SDT appreciates your position, from past experience information
contained outside of the requirement is not enforceable and cannot be used
for determination of compliance. Therefore, any exclusions must be
contained in the requirements.

The SDT should be commended for its work in putting forward this
draft. However, there are a number of areas where the draft can be
improved before adoption by NERC.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Answer Comment:

Jeri Freimuth - APS - Arizona Public Service Co. - 3 –

Response:

14

R1.3. AZPS is concerned that the NERC Glossary of Terms only allows a BA or
LSE to be in an EEA. And EOP-002-3.1 R7 and R8 have the Balancing
Authority requesting to be declared in an EEA. If a Balancing Authority were
in an RSG, that would make the RSG the Responsible Entity under BAL-002-

R1.2. should not be included in the requirements section. This administrative
function would violate FERC P81 as administrative in nature. Also, the
process or form could change.
The SDT disagrees with the characterization that this is a Paragraph 81 issue.
The Requirement R1 part 1.2 requires a specific calculation in the form. This
ensures all entities subject to compliance utilize the same methodology for
each event. There is not a reporting requirement in the standard.

from R1. The obligation to restore Contingency Reserve should be merged
into R1.
While the SDT appreciates your position, we believe that R3 is significantly
different than R1. R1 requires an entity to recover from an event within a 15
minute window. R3 requires an entity to essentially modify their day-ahead
plan to address the circumstance in the real-time and to address the next
contingency if it were to occur. There is no expectation to carry reserves
during the Contingency Reserve Restoration Period. Additionally,
Requirement R3 carries forward the intent of the current BAL-002-1
Requirement R6.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Answer Comment:

15

The recovery value for any Balancing Contingency Event(s) that occurs

BPA is in agreement with the proposed standard. However, BPA believes
there should be a clarifying comment in requirement R1. In R1, subrequirement 1.1, following the second bullet, BPA would like the standard to
state:

Andrea Jessup - Bonneville Power Administration - 1,3,5,6 – WECC –

Response:

R2. If we understand correctly, this requirement is extending the
requirement of EOP-011-1 R2 by reference. We do not believe it is advisable
to include a requirement that adds to the elements of another requirement
in a separate standard. It raises tangential questions such as “does this
Operating Process have to be RC-approved as the Operating Plan does?”
There is no relation to EOP-011-1 R2. While this requirement does reference
an Operating Plan, it is not the same Operating Plan referenced in EOP-011-1
R2. Instead, the Operating Plan referenced in BAL-002-2 may be the same
Operating Plan required under R4 of TOP-002-4, specifically part 4.4.

2. If the BA was experiencing and requested an EEA, does this transfer
exception allowed in R1.3 to the RSG as not being subject to compliance?
If a Balancing Authority is experiencing an EEA event under which its
contingency reserves have been activated, the RSG in which it resides would
also be considered to be exempt from R1 compliance. The RC should have
gone through all steps prior to an EEA.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Answer Comment:

Richard Vine - California ISO - 2 -

Response:

16

1. The High VSL for R2 in the proposed BAL-002-2, as well as auditor
guidance in the proposed BAL-002-2 RSAW, could be interpreted to require
Contingency Reserve to be > MSSC at all times other than when deployed in
response to a Balancing Contingency Event. However, in the Western
Interconnection BAL-002-WECC-2 allows clock-hour averaging to determine if
Contingency Reserves were adequately maintained. How will this apparent
conflicting methodology be reconciled if BAL-002-2 is passed?
The SDT agrees that the RSAW could be interpreted in such a manner to not
meet the intent of the requirement. The RSAW is being modified to clarify
the necessary compliance elements for the next posting. The Contingency
Reserve requirement in R2 is only for an Operating Process that determines
and plans for Contingency Reserves. There should not be any real-time
measurement for Contingency Reserves in R2, unlike in the WECC Regional
Standard. Therefore, there is no conflict.

during the Contingency Event Recovery Period shall be the recovery value
for the initial event.
While the SDT understands your comment, there is no required recovery
value for a Balancing Contingency Event in this standard. Recovery values are
only used for Reportable Balancing Contingency Events. Please refer to CR
Form 1 to determine how the recovery value is determined for multiple
events.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Answer Comment:

Spencer Tacke - Modesto Irrigation District - 4 –

Response:

17

1.
A specific percent change in ACE (Area Control Error) needs to be
specified in the definition of Reportable Balancing Contingency Event, where
it states “…sudden decline in ACE based on EMS scan rate…” (on page 3).

I am recommending a NO vote for the following reasons:

2. The definition of Contingency Reserve in the proposed BAL-002-2 indicates
this is capacity that may be deployed to respond to a Balancing Contingency
Event. However, R3 states “Each Responsible Entity, following a Reportable
Balancing Contingency Event, shall restore Contingency Reserve to at least
its Most Severe Single Contingency before the end of the Contingency
Reserve Restoration Period...". The proposed standard does not identify how
long an entity has to return Contingency Reserve following deployment for a
Balancing Contingency Event (i.e. - not "Reportable").
There is no recovery period required for a Balancing Contingency Event nor is
there reserve restoration period associated with a Balancing Contingency
Event. However, if a Reportable Balancing Contingency Event occurs the
required time frame for reportable events will be reviewed to determine if
the Balancing Contingency Event impacts the compliance responsibility. As
an example, a Balancing Contingency Event that occurs two hours prior to a
Reportable Balancing Contingency Event will not reduce the response
requirement for the Reportable Balancing Contingency Event but a Balancing
Contingency Event that occurs one hour prior to the Reportable Balancing
Contingency Event may. Please refer to Requirement R1 Part 1.3.2.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

18

4.
Under the Rationale for Requirement R1 on page 7, the phrase
“..returns its Area Control Error (ACE) to defined values…” should include a
locational reference to the actual defined values (i.e., what are they and
where can they be found ?).
The defined values are determined in Requirement R1 Part 1.1. The
Rationale boxes are not enforceable and are moved to another area of the
standard when the standard is filed.

3.
Under the Contingency Reserve Restoration Period definition on page
4, the period should be 30 minutes instead of 90 minutes in order to be
consistent with the NERC TOP-004 (Transmission Operations) Standard.
There is no direct coorelation between the time frames in the two standards.
Your proposal would reduce the current restoration which has proven to
provide an adequate level of reliability over the years.

2.
Using arbitrary MW definitions for each major Interconnection (on
page 4) under the same section on the definition of a Reportable Balancing
Contingency Event, may lead to inconsistent results, as the MW values
actually needed are dynamic and based on the amount of load and on-line
generation at the time of the disturbance or contingency event.
The MW thresholds are based on a statistical evaluation of historical events
in each interconnection and their impact on system frequency. Please refer
to the Background Document posted with this standard. Your proposal
would make it more difficult to determine the point at which an event
becomes a Reportable Balancing Contingency Event. The SDT utilized
conservative numbers in order to provide the System Operators with the
necessary information to operate the grid while maintaining compliance.

The reporting threshold is based on the size of the resource loss not the
change in ACE. Therefore, no specific change in ACE is necessary.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Answer Comment:

Anthony Jablonski - ReliabilityFirst - 10 –

Response:

19

i. There is a disconnect between the lead in Part 1.3.1 and the third
bullet. The lead in states “the Responsible Entity is:” and the third bullet
states “the Responsible Entity has depleted…”. As one can see, there is a

1. Requirement R1, Part 1.3.1

ReliabilityFirst votes in the Affirmative because the standard helps to better
ensure the Balancing Authority or Reserve Sharing Group balances
resources and demand and returns the Balancing Authority's or Reserve
Sharing Group's Area Control Error to defined values (subject to applicable
limits) following a Reportable Balancing Contingency Event. ReliabilityFirst
offers the following comments for consideration:

209-526-7414

Modesto Irrigation District

Senior Electrical Engineer

Spencer Tacke

Sincerely,

Thank you.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Answer Comment:

20

R2 M2 Contingency Reserves can and should be deployed for reasons to
include loss of resources temporarily till mitigation measures are
implemented less than MSSC. M2 does not make it clear that reserves can
be used for any other resource loss less than MSSC. It appears you have to

R 1.1.2 Reporting should not be a requirement.
R1 part 1.2 does not require a report to be submitted. Instead it requires the
calculation to be on the referenced form. This ensures all entities subject to
compliance utilize the same methodology for each event.

Edward Magic - SCANA - South Carolina Electric and Gas Co. - 5 –

Response:

• has depleted its Contingency Reserve to a level below its Most Severe
Single Contingency
The SDT agrees with your comment and has modified the language.

• [is] utilizing its Contingency Reserve to mitigate an operating
emergency in accordance with its emergency Operating Plan, and

• [is] experiencing a Reliability Coordinator declared Energy Emergency
Alert Level, and

1.3.1 the Responsible Entity:

double use of the term “the Responsible Entity”. RF recommends the
following language for consideration:

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Group Member Name
Charlie Freibert
Brenda Truhe
Dan Wilson
Linn Oelker

Group Name:

Entity
LG&E and KU Energy, LLC
PPL Electric Utilities Corporation
LG&E and KU Energy, LLC
LG&E and KU Energy, LLC

PPL NERC Registered Affiliates

Joseph Bencomo - LG&E and KU Energy LLC - 1,3,5,6 - SERC,RFC -

Response:

Region
SERC
RFC
SERC
SERC

Segments
3
1
5
6

21

The BAL-002-2 RSAW posted further supports our primary concern “Review
the evidence and verify that the entity had available Contingency reserves
equal to, or greater than its Most Severe Single Contingency” Suggest the
wording be revised “Confirm the applicable Entity met the Contingency
Requirement for Reportable Balancing Contingency Event(s)”
The SDT agrees that the RSAW could be interpreted in such a manner to not
meet the intent of the requirement. The RSAW is being modified to clarify
the necessary compliance elements for the next posting. Further
Requirement R2 and Measure M2 have no bearing on utilization of
Contingency Reserve. Rather it is only a requirement to plan to have
Contingency Reserve as part of you Operating Plan.

provide data that you had reserves >= MSSC each hour.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Answer Comment:

22

BAL-001-2 becomes enforceable 7/1/2016, R2 (BAAL performance) will
incent the appropriate BA/RSG action to a Reportable BCE without forcing

The proposed draft 7 requires reporting and compliance evaluation of each
individual Reportable BCE. Quarterly reporting and evaluation of Reportable
Events on a quarterly basis has worked well and should be continued.
The proposed standard does not require any reporting. The language as
drafted is proposed to address a directive from FERC Order 693 Paragraph
354 which requires compliance based on individual events.

4.1.1.1. A Balancing Authority that is not a member of a NERC registered
Reserve Sharing Group is the Responsible Entity.
The SDT appreciates your comment. However, the proposed language
provides the flexibility for RSGs to allow members to participate on an eventby-event basis as some RSGs currently allow.

Suggested solution – Modify language in 4.1.1.1 to:

Clarity is needed as to whether or if a BA that is a member of an RSG but
does not request RSG assistance for a specific BCE is considered the
Responsible Entity. The “active status” language used in 4.1.1.1 is unclear.

Comments

These comments are submitted on behalf of the following PPL NERC
Registered Affiliates (PPL): LG&E and KU Energy, LLC and PPL Electric Utilities
Corporation. The PPL NERC Registered Affiliates are registered in two regions
(RFC and SERC) for one or more of the following NERC functions: BA, DP, GO,
GOP, IA, LSE, PA, PSE, RP, TO, TOP, TP, and TSP.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

23

The exemption in Requirement R1 Part 1.3 is applicable only to Requirement
R1 Part 1.1. Entities that experience events that meet the exemption for

1.3. deploy Contingency Reserve, within system constraints, to respond to all
Reportable Balancing Contingency Events, however, it is not subject to
compliance with Requirement R1 parts 1.1 and 1.2 and R3 if:
The entity experiencing any of the scenarios in Requirement R1 Part 1.3 is
exempt from compliance for Requirement R1 Part 1.1.

Suggested solution – Modify language in 1.3 to:

For a Responsible Entity experiencing an EEA, compliance with BAL-002-2 R3
is not consistent with actions required under the EEA.

An entity experiencing an EEA (or any of the other exemption scenarios in
R1.3) should not be required to restore ACE as stated in R1.1, document the
Reportable BCE as per 1.2 or restore Contingency Reserves to MSSC within
the Contingency Restoration Period as stated in R3.

The language in R1.3 related to an exemption from R1.1 needs to be
applicable to R1 and R3.

action that could be contrary to interconnect frequency stability. BAL-001-2
has negated the need for BAL-002-2.
Until BAL-001-2 has been fully implemented, data has been collected and
evaluated, it would be difficult to show the reliability impacts of a complete
retirement of BAL-002-1. Further, the team has determined that there is a
reliability gap absent BAL-002-2. Also, through the standard development
process for this project, numerous issues with the current standard have
been identified. As such, the proposed standard provides clarity for the
issues that have been identified to date.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Rob Vance
Paul Malozewski

Mark Kenny
Helen Lainis

Gerry Dunbar

Sylvain Clermont
Kelly Dash

David Burke
Greg Campoli

Group Member Name
Alan Adamson

Group Name:

Entity
New York State Reliability Council,
LLC
Orange and Rockland Utilities Inc.
New York Independent System
Operator
Hydro-Quebec TransEnergie
Consolidated Edison Co. of New
York, Inc.
Northeast Power Coordinating
Council
Northeast Utilities
Independent Electricity System
Operator
New Brunswick Power Corporation
Hydro One Networks Inc.

NPCC--Project 2010-14.1

Lee Pedowicz - Northeast Power Coordinating Council - 10 – NPCC -

Response:

NPCC
NPCC

NPCC
NPCC

NPCC

NPCC
NPCC

NPCC
NPCC

9
1

1
2

10

1
1

3
2

Region Segments
NPCC
10

24

Requirement R1 Part 1.1 should still be able to document the Reportable
Balancing Contingency Event s under Part 1.2. The definition of Contingency
Reserve addresses your concern related to Requirement R3 by allowing firm
load readied to be removed from the system, thus allowing the load to count
as Contingency Reserve.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Answer Comment:

Silvia Parada Mitchell
Kathleen Goodman
Robert Pellegrini

Connie Lowe
Guy Zito

RuiDa Shu

Glen Smith
Brian O'Boyle

Michael Jones
Brian Shanahan
Michael Forte

Si Truc Phan
David Ramkalawan
Brian Robinson
Wayne Sipperly
Edward Bedder
Peter Yost

Bruce Metruck
Lee Pedowicz

NPCC
NPCC
NPCC

NPCC
NPCC

NPCC

NPCC
NPCC

NPCC
NPCC
NPCC

NPCC
NPCC
NPCC
NPCC
NPCC
NPCC

NPCC
NPCC

5
2
1

5
10

10

5
8

1
1
1

1
5
8
5
1
3

6
10

25

With the requirements as written, the Responsible Entity should include the
Reliability Coordinator. As defined in the NERC Reliability Functional Model
Version 5 for the Reliability Coordinator, Balancing operations:

New York Power Authority
Northeast Power Coordinating
Council
Hydro-Quebec TransEnergie
Ontario Power Generation, Inc.
Utility Services
New York Power Authority
Orange and Rockland Utilities Inc.
Consolidated Edison Co. of New
York, Inc.
National Grid
National Grid
Consolidated Edison Co. of New
York, Inc.
Entergy Services, Inc.
Consolidated Edison Co. of New
York, Inc.
Northeast Power Coordinating
Council
Dominion Resources Services, Inc.
Northeast Power Coordinating
Council
NextEra Energy, LLC
ISO - New England
The United Illuminating Company

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

26

Regarding the wording used to define the Most Severe Single Contingency
(MSSC), as it reads now the MSSC is defined as “The Balancing Contingency
Event, due to a single contingency as identified and maintained in the system
models within the Reserve Sharing Group (RSG) or a Balancing Authority’s
area that is not part of a Reserve Sharing Group, that would result in the
greatest loss ...”.

1.4 Restore its Contingency Reserve to at least its Most Severe Single
Contingency before the end of the Contingency Reserve
Restoration
Period.
The SDT discussed this and determined that the restoration of ACE and the
restoration of Contingency Reserve are two separate and distinct actions.
Therefore the SDT believes that these two actions should be covered under
two separate requirements.

Consider incorporating Requirement R3 into Requirement R1 by adding the
following Part 1.4:

“Balancing operations. The Reliability Coordinator ensures that the
generation-demand balance is maintained within its Reliability Coordinator
Area, which, in turn, ensures that the Interconnection frequency remains
within acceptable limits. The Balancing Authority has the responsibility for
generation-demand-interchange balance in the Balancing Authority Area. The
Reliability Coordinator may direct a Balancing Authority within its Reliability
Coordinator Area to take whatever action is necessary to ensure that this
balance does not adversely impact reliability.”
The SDT does not believe that this standard should include any requirements
on the Reliability Coordinator. The Reliability Coordinator is governed by
requirements located in the IRO standards.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

27

In addition, the wording in the third bullet of Part 1.3.1 (Part 1.3.1 needs
identification in the draft) needs clarification. For example, if your MSSC is a
resource loss of 400 MW, this Part’s wording would suggest that the
depletion of "Contingency Reserve to a level below its Most Severe Single
Contingency" would refer to a value of less than 400 MW. You might deplete

We feel the time requirement to declare an EEA of any level prior to 1.1
being waived is an unnecessary operations burden during the Contingency
Event Recovery Period. It could result in an entity being non-compliant
because complete recovery is delayed by the time it takes to go through the
"declaration" process. We feel the new standard is adding an exposure to
non-compliance because of the need for the RC to declare an emergency
prior to the waiver of the ACE correction requirement in Part 1.1. Within
NPCC there are entities that fill both the RC role that declares the EOP-002-3
Energy Emergency Alert level, and the BA role that BAL-002-2 will apply to.
The SDT believes that the proposed requirement under Requirement R1, Part
1.1 is not an undue burden because the use of an EEA is not applicable to this
standard and is not appropriate as a solution for complying with
Requirement R1 Part 1.1. If an entity is not in the EEA prior to a loss, the
waiver of R1 Part 1.1 would not apply.

The process used to find the MSSC uses system models and does allow the
modelling of contingencies.
For clarity, suggest revising the wording in the definition. The models
themselves neither identify contingencies nor are contingencies “maintained
in” them. Suggest eliminating the words “…as identified and maintained in
the system models within the Reserve Sharing Group (RSG) or a Balancing
Authority’s area that is not part of a Reserve Sharing Group…”or replacing
the words “identified and maintained in the system models within” with the
following: “identified using system models maintained within…”.
The SDT has made the necessary modifications.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Answer Comment:

Group Member Name
Shannon Mickens
Jason Smith
Carl Stelly
Mahmood Safi
Jes Gray

Group Name:

Region
SPP
SPP
SPP
MRO
MRO

Segments
2
2
2
1,3,5
1,3,5

28

We would suggest to the drafting teams developing coordinated efforts with
the Alignment of Terms Standards Draft Team (Project 2015-04). The
collaborative efforts would pertain to the revised and newly proposed terms
in BAL-002-2 which would help ensure that these terms are included in both

Entity
Southwest Power Pool Inc.
Southwest Power Pool Inc
Southwest Power Pool Inc
Omaha Public Power District
Omaha Public Power District

SPP Standards Review Group

Shannon Mickens - Southwest Power Pool, Inc. (RTO) - 2 – SPP –

Response:

your reserves by 250 MW and still have 150 MW remaining to meet another
contingency after the initial event which may be sufficient and not require a
waiver. We suspect that the intention is that all of the MSSC determined
value of required reserve is depleted before the waiver is allowed.
The intention of the bullet is that if an entity utilizes its Contingency Reserve
such that it dips below its MSSC, regardless of the magnitude, the entity can
no longer fully respond to meet Requirement R1 if its MSSC occurs.
Therefore, Requirement R1 Part 1.3.1 allows an exemption from compliance
if all of the three bullets are occurring at the same time.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

29

In the Rationale section for Requirement R1, the drafting team mentions
“The current EEA levels suggest that when an entity is experiencing an EEA
Level 2 or 3 it is short of Contingency Reserves as normally defined to exclude
readiness to curtail a specific amount of Firm Demand. Under the proposed
EEA process, this would only be during an EEA Level 3. In order to reduce the
need for consequent modifications of the BAL-002 standard, the drafting
team has developed the proposed language”. We would ask the drafting
team to provide more clarity on what direction BAL-002-2 is going in
reference to the EEA. The rationale states that the drafting team has
developed proposed language. Can we assume this proposed language is
currently in the standard and if so, will this language match up with the
NERC’s process changes to the EEA levels (which hasn’t been developed yet)?
The next question would be….will these process changes be vetted through
the voting process or will it be the law of the land?

Our review group also noticed that the drafting team uses the acronym ‘RE’
several times (second paragraph on page 4) in the Rationale for Contingency
Reserve Definition section of the standard. We will make the assumption that
you are referring to the term ‘Responsible Entity’. However, we would
suggest either using it as an appositive with the term or removing it from the
document completely. We feel that some confusion will arise amongst the
industry on what ‘RE’ is being referred to. For example, ‘RE’ could refer to
‘Regional Entity’ or ‘Registered Entity’.
The SDT has made the appropriate modifications.

the NERC Glossary of Terms as well as the Rules of Procedure for proper
alignment (which can be addressed in Phase II of their project). Of course,
this collaborative effort would take place once NERC’s BoT and FERC
approves the proposed terms and standard pertaining to this current project.
If a proposed definition is also in the Rules of Procedure, the drafting team
will work with NERC to ensure that alignment is maintained going forward.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Albert DiCaprio - PJM Interconnection, L.L.C. - 2 – RFC -

Response:

30

Finally, we would like to suggest to the drafting team once the terms and
standards have been approved by the NERC BoT and FERC to follow up on
this project and ensure that the RSAW be properly aligned with this standard.
The SDT agrees that the RSAW could be interpreted in such a manner to not
meet the intent of the requirement. The RSAW is being modified to clarify
the necessary compliance elements for the next posting.

Our group understands that the conversation pertaining to the retirement of
BAL-002-2 is in the distant future. However, we have the concern that there
are current documentation in place that helps serve the industries needs in
reference to the MSSC. With that being said, we feel that BAL-002-2 brings
confusion and redundancy to the industry and we would suggest that the
drafting team take into consideration the retirement of this standard.
Until BAL-001-2 has been fully implemented, data has been collected and
evaluated, it would be difficult to show the reliability impacts of a complete
retirement of BAL-002-1. Further, the team has determined that there is a
reliability gap absent BAL-002-2. Also, through the standard development
process for this project, numerous issues with the current standard have
been identified. As such, the proposed standard provides clarity for the
issues that have been identified to date.

The SDT has made the necessary clarification to the Rationale Box. Please
note that the proposed EEA changes were developed as part of the EOP-0111 standard currently filed at FERC.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Answer Comment:

Group Member Name
Charles Yeung
Ben Li
Mark Holman
Kathleen Goodman
Greg Campoli
Christina V. Bigelow
Ali Miremadi

Group Name:
Region
SPP
NPCC
RFC
NPCC
NPCC
TRE
WECC

Segments
2
2
2
2
2
2
2

Eliminate draft 6’s hourly obligations; and

·

Links MSSC to BCE; and

The SRC does not agree with proposed standard wording that:

31

·
Clarify that shedding load is not an expected action in order to maintain
reserves.

·

·
Ensure that the definition of BCE does recognize the possibility of the
loss of more than one resource;

·
Ensure that the definition of Most Severe Single Contingency (MSSC)
does not include more than one resource;

·
Provide the risk based parameters (ACE range, Recovery period,
Restoration period) for responding to a Balancing Contingency Event (BCE);

The SRC agrees with the intention of the SDT draft 7 posting to:

Entity
SPP
IESO
PJM
ISONE
NYISO
ERCOT
CAISO

ISO Standards Review Committee

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

MSSC;
Contingency Event Recovery Period; and
The EEA level referenced in R1.3.1

·
·
·

32

The SRC would ask that the SDT to redraft the requirements in more direct
terms. Phrases like “demonstrate recovery” in the requirement section of the
standard can be construed ambiguously and a clear reliability requirement
omits unnecessary words and directly defines the obligation.

Revisions Proposed To Facilitate Clarity

The SRC has characterized its comments in three classifications: those
proposed to facilitate clarity; those proposed to ensure that the focus of
requirements remains on reliability; and those proposed to address other
concerns.

The SRC again asks the SDT to remove the language within draft 7’s proposed
CR requirement that ties DCS compliance to the use of CR.

Balancing Contingency Events;

·

The SRC proposes clarifying modifications to definitions for:

·
Links Contingency Reserves (CR) to Disturbance Control Standard (DCS)
compliance.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Requirement R1.3 defines Contingency Reserve deployment;

Retaining current draft language:

33

• zero (if its Pre-Reporting Contingency Event ACE Value was positive or
equal to zero); however, any Balancing Contingency Event that occurs during
the Contingency Event Recovery Period shall reduce the required recovery: (i)
beginning at the time of, and (ii) by the magnitude of, such individual
Balancing Contingency Event,

1.1. within the Contingency Event Recovery Period, demonstrate recovery by
returning its Reporting ACE to at least the recovery value of:

R1. The Responsible Entity experiencing a Reportable Balancing Contingency
Event shall:

1.

This organization does not allow readers and entities responsible for
compliance and direct correlation between specific defined obligations and
the proposed exemptions. To facilitate clarity, the SRC offers two
recommendations. The first recommendation preserves much of the current,
draft language while the second recommendation provides more streamlined
language:

·
Sub-Requirements of R 1.3 then introduce exceptions for R1.1 (i.e., R
1.3.1 and R 1.3.2).

·

·
Requirement R1.1 defines the target ACE correction (range of
recovery);

In particular, the SRC suggests that the linkage between R 1.1 and R1.31 is a
source of ambiguity within the standard because:

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

the responsible entity:

the following subsequent event(s) occur:
1.3.2 the Responsible Entity experiences:

·

or,

34

•
is experiencing any Reliability Coordinator-declared Energy
Emergency Alert Level 1 or higher; is utilizing its Contingency Reserve to
mitigate an operating emergency in accordance with its emergency
Operating Plan; or has depleted its Contingency Reserve to a level below its
Most Severe Single Contingency .

·

Unless:

1.3. deploy Contingency Reserve, within system constraints, to respond to all
Reportable Balancing Contingency Events, however, it is not subject to
compliance with Requirement R1 part 1.1 if: 1.3.1 the Responsible Entity is:

1.2. document all Reportable Balancing Contingency Events using CR Form 1.

• its Pre-Reporting Contingency Event ACE Value (if its Pre-Reporting
Contingency Event ACE Value was negative); however, any Balancing
Contingency Event that occurs during the Contingency Event Recovery Period
shall reduce the required recovery: (i) beginning at the time of, and (ii) by the
magnitude of, such individual Balancing Contingency Event.

or,

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

More direct version:

35

Where a Balancing Contingency Event exceeds the responsible entity’s MSSC
or multiple Balancing Contingency Events occur within the Contingency Event
Restoration period of the 1st RBCE, the responsible entity shall deploy
contingency reserves, but such response shall not be subject to Requirement
R1:

·
Its Pre-RBCE ACE Value if the Responsible Entity’s Pre-RBCE ACE Value
were negative

·
Zero within the Contingency Event Recovery Period if the Responsible
Entity’s Pre-RBCE ACE Value were positive or equal to zero; or

R1.
Unless the Responsible Entity is experiencing any Reliability
Coordinator-declared Energy Emergency Alert Level 1 or higher, is utilizing its
Contingency Reserve to mitigate an operating emergency in accordance with
its emergency Operating Plan, or has depleted its Contingency Reserve to a
level below its Most Severe Single Contingency, , the Responsible Entity
experiencing a Reportable Balancing Contingency Event (RBCE) shall return its
ACE to:

1.

•
multiple Balancing Contingency Events within the sum of the time
periods defined by the Contingency Event Recovery Period and Contingency
Reserve Restoration Period whose combined magnitude exceeds the
Responsible Entity's Most Severe Single Contingency.

•
multiple Contingencies where the combined MW loss exceeds its
Most Severe Single Contingency and that are defined as a single Balancing
Contingency Even;, or

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

·

36

an annual obligation to compute MSSC and to use that annually-

requirement is administrative in nature as it mandates a creation of a
procedure, an implementation process for that procedure, as well as a
mandate to “have” a market service to calculate MSSC. The sentence in draft
7 can be read as ether:

The SRC does recognize the SDT’s attempt to address the issue of
maintaining reserves designed to preserve serving load verses the issue of
shedding load to preserve reserves and that it makes no sense to shed load
to maintain reserves that are designed to protect load from being
shed. Additionally, the SRC questions the need for the proposed
Requirement R2 (i.e., the requirement to have a method to compute
MSSC). Such

The SRC asserts that the primary focus of BAL-002 should be reliability (ACE
recovery) with less focus be given to the specific process regarding how to
meet the reliability requirement. The current draft appears to link economic
sharing arrangements (Contingency Reserves) to a reliability requirement
and, therefore, precludes the use of more effective processes to meet the
reliability requirement. The SRC cautions the SDT against mandating the use
of a process where such usage would be inappropriate from both a reliability
and cost efficiency perspective when other processes are available For
example, as written, draft 7 could preclude the use of Demand Side
Management (DSM) as Contingency Reserves (in contradiction of Order
1000), and restricting DSM to Emergencies only. For these reasons, the
requirements should be re-focused on what needs to occur for reliability –
not how such activities are performed.

Revisions proposed to ensure that the focus of requirements remains on
reliability

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

carry an equivalent amount of reserves for that year

carry an equivalent amount of RC (for as long as the plan states)

37

The definition of MSSC is axiomatic and does not require a formal procedure.
The only plausible justification for having such a plan is mandate selfimposed rules regarding when to compute MSSC; how to apply that
calculation; and for how long. Given the ambiguity in draft 7’s R2, either
approach can be justified. Such ambiguity would not serve reliability. As an
example, if draft 7 really did intend linking MSSC to an annual value, and in
doing so lock-in a minimum reporting value (80% of MSSC), then what could
occur is that small BAs can have a minimum reportable value that is larger
than any unit that is operating on a given day – in effect - exempting them
from ever reporting. On the other hand, if draft 7 really did intend to provide
flexibility to the BAs, a number of questions arise: Is this a daily scheduling
function, or a continuous operating function? Is the objective fixed or does it
depend on what is operating at the given time? Accordingly, the current
approach could be interpreted broadly and variably and should be revised as
it does not appear to be directly focused on or facilitating reliability.

·

·
implement the computation ( the implication is that the plan will
introduce the time frame for updating MSSC)

·
develop a plan to explain how to compute MSSC and review that plan
every year

or

·

computed MSSC in system operations, and

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

38

The SRC requests that the SDT explain its correlation between the reporting
requirement and P 354 and requests that the SDT clarify the timing of any
required reporting. Additionally, the SRC is unclear as to how “the VSL levels

354. First, the Commission directs the ERO to develop a modification to the
Reliability Standard requiring that any single reportable disturbance that has
a recovery time of 15 minutes or longer be reported as a violation of the
Disturbance Control Standard. This is consistent with our position in the
NOPR and NERC’s position in response to the Staff Preliminary Assessment of
the Requirements in BAL-002-0, and was not disputed or commented upon
by any NOPR commenters.

2.
The standard has a reporting requirement, but does not include a
reporting timeframe. Therefore, the most conservative assumption would be
that reporting is on and “individual event” basis. For draft 7, the SDT
rejected quarterly reporting based on a non-relevant paragraph in Order 693.

1.
Delete the phrase “within system constraints” in Requirement
R1. Because BAs are not responsible for system constraints (that’s the role of
TOP), the inclusion of this phrase connotes that a BA can be held responsible
for exacerbating a SOL problem, even if the BA had no knowledge of the limit
and was taking actions to comply with its obligations. The requirements
should respect current roles and responsibilities of the various functions and,
currently, the TOP is responsible for directing the BA in this regard.

The SRC suggests the following comments and/or revisions for the SDT’s
consideration:

Revisions Proposed to Address Other Concerns

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Draft 7 definition of Event:

39

Most Severe Single Contingency (MSSC): The Balancing Contingency Event,
due to a single contingency as identified and maintained in the system
models within the Reserve Sharing Group (RSG) or a Balancing Authority’s
area that is not part of a Reserve Sharing Group, that would result in the
greatest loss (measured in MW) of resource output used by the RSG or a
Balancing Authority that is not participating as a member of a RSG at the time
of the event to meet Firm Demand and export obligation (excluding export
obligation for which Contingency Reserve obligations are being met by the
Sink Balancing Authority).

Draft 7 definition of MSSC:

1.
The Draft 7 definitions of MSSC and BCE do not resolve the issue of BCE
being greater than the MSSC because Draft 7 continues to link the definitions
of MSSC and BCE. The SRC believes MSSC is an a priori / actual state value
while BCE is an a posteriori event/experience. The SRC agrees with the SDT
that MSSC can never be more than one resource otherwise it would not be a
“single contingency.” BCE on the other hand can (as the current definition
indicates) include the impacts of the loss of more than one resource. To
address this concern, the SRC offers the following comments and revisions.

developed were likely to place smaller BA’s and RSGs in a severe violation
regardless of the size of the failure.” Upon review, it appears that values for
entities are calculated on a % of recovery whether applied to an individual
event or quarterly performance – accordingly the severity of a violation
would still be correlated to overall performance for some time period. The
SRC requests that the SDT re-evaluate its explanation and provide additional
clarification.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

40

Given the above definitions, the SRC concludes that the SDT correctly wants
to ensure that MSSC include large interchange schedule imports as well as
large generators. The definition of BCE does that (see sub item B). The draft 7
definition of MSSC relies on the definition of BCE to ensure that such
interchange gets considered. The problem is that the foreword of the BCE
definition includes the phrase “or any series of such otherwise single events.”
That addition makes it virtually impossible to quantify / limit one single

C. Sudden restoration of a Demand that was used as a resource that causes
an unexpected change to the responsible entity’s ACE.

B. Sudden loss of an import, due to unplanned outage of transmission
equipment that causes an unexpected imbalance between generation and
Demand on the Interconnection.

b. And, that causes an unexpected change to the responsible entity’s ACE;

iii. sudden unplanned outage of transmission Facility;

ii. loss of generator Facility resulting in isolation of the generator from the
Bulk Electric System or from the responsible entity’s System, or

i. unit tripping,

a. Due to

A. Sudden loss of generation:

Any single event described in Subsections (A), (B), or (C) below, or any series
of such otherwise single events, with each separated from the next by one
minute or less.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

41

The Draft 7 definition CR does not define what CR is, but rather defines what
CR may be used for. Moreover, the definition’s use of the phrase “provision
of capacity” requires further explanation to clearly delineate between the
concept of “provision of capacity” in the Operating Planning environment
(meaning to request that resource be made available to serve load) versus
the “provision of capacity” in the compliance/operating environment
(meaning the amount of energy that was produced at the request of the
BA). An additional issue with the first sentence is that, as written, it
specifically excludes the use of those reserves to serve firm customer load.
To address this concern, the SRC offers the following comments and
revisions.

·
Can be used to provide clarity concerning why and how the amount of
CR can be set to a daily MSSC; and how and why every CBE can be “reported”
upon without being subject to the DCS objectives for an MSSC.

·
Changes the MSSC definition from being linked to a Balancing
Contingency Event of undefined size, to linking MSSC to an easily identified
single resource capacity/expectation.

This revision:

MSSC is the MW capacity of the single largest resource scheduled to operate
for a given day’s peak load. The resource may be a generator (Maximum
Continuous Operating Capacity) or a Firm Interchange scheduled import.

The SRC would suggest that Draft 7 definition of Event be retained, but that
the definition of MSSC be redrafted. The SRC suggests:

resource amount for an MSSC.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Response: Please refer to the response to these comments at Page 76.

42

·
Reserves were linked to day ahead scheduling in the sense that
“reserve” capacity over and above the capacity scheduled to meet a peak
load. This concept was referenced in the original Policy 1 – Generation
Control and Performance, (dated Feb 1, 1997) at romanette ([i]) If CR were
viewed as scheduled available system capacity there would be no issue,
because then the measurement of reserves would be focused on the planned
capacity for the day. Once that capacity is synchronized it can be used for any
and all purposes.

The SRC suggests that the issue of CR and reserves in general requires an
Industry-wide review; and the SDT in its introduction to its Response to
Comments propose the ERO conduct such a review prior to making a decision
on a final ballot. The review would be used to decide if:

• is utilizing its Contingency Reserve to mitigate an operating emergency
in accordance with its emergency Operating Plan.

• is experiencing a Reliability Coordinator declared Energy Emergency
Alert level, and

Draft 7 definition of Contingency Reserve: The provision of capacity that
may be deployed by the Balancing Authority to respond to a Balancing
Contingency Event and other contingency requirements (such as Energy
Emergency Alerts as specified in the associated EOP standard). A Balancing
Authority may include in its restoration of Contingency Reserve readiness to
reduce Firm Demand and include it if, and only if, the Balancing Authority:

Draft 7 definition of Contingency Reserves

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Answer Comment:

Mark Holman - PJM Interconnection, L.L.C. - 2 -

43

Most Severe Single Contingency (MSSC): The loss of a single Element as
identified and maintained in the system models within the Reserve Sharing
Group (RSG) or a Balancing Authority’s area that is not part of a Reserve
Sharing Group, or the sudden loss of an import, or the sudden restoration of
a Demand that was used as a resource, that would result in the greatest loss
(measured in MW) of resource output used by the RSG or a Balancing
Authority that is not participating as a member of a RSG at the time of the
event to meet Firm Demand and export obligation (excluding export
obligation for which Contingency Reserve obligations are being met by the
Sink Balancing Authority).
The SDT does not believe that your structural changes provides any
additional clarity to the proposed definition to the proposed definition.

MSSC: As written the MSSC definition is linked to and dependent on the
definition of a Balancing Contingency Event. In doing so an RE must
determine its MSSC based on a Balancing Contingency Event, or series of
events including imports, separated by one minute, that have not occurred.
As long as the definition of MSSC is dependent on the definition of a BCE, we
suggest that MSSC is incalculable and propose the change below.

Definitions

We would like to thank the SDT for their work on this proposed revision to
BAL-002-1 and the opportunity to provide comments.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

44

We understand the intent of the SDT, however, R1.3 states that an RE must
deploy Contingency Reserve for all Report Balancing Contingency Events
regardless of whether there is a need to deploy Contingency Reserve to
comply with R1.1. Recovery is often accomplished through frequency
responsive and regulation resources. Additionally, R1.3 as written could be

Requirement 1:

• is utilizing its Contingency Reserve to mitigate an operating emergency
in accordance with its emergency Operating Plan.
The SDT believes that your suggested modification to the first bullet appears
to duplicate the second bullet while adding a potential burden to compliance.

• is experiencing a Reliability Coordinator declared Energy Emergency
Alert level where an energy deficient BA is not able to maintain minimum
Contingency Reserve requirements, and

Contingency Reserve: The resource capacity, measured in MW, above that
serving Firm Demand, that may be deployed by the Balancing Authority to
respond to a Balancing Contingency Event and other contingency
requirements (such as Energy Emergency Alerts as specified in the associated
EOP standard). A Balancing Authority may include in its restoration of
Contingency Reserve readiness to reduce Firm Demand and include it if, and
only if, the Balancing Authority:

We propose the following changes for clarity.

Contingency Reserve: As written, the criteria for allowing readiness to
reduce Firm Demand in Contingency Reserve is ambiguous. We suggest
adding clarifying language to clearly state when the readiness to reduce Firm
Demand will be accepted as Contingency Reserve.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

45

Additionally, we suggest that the phrase “within system constraints” should
be removed because BA’s are not responsible for system constraints; that
being the role of the TOP. The TOP standards address system constraints and
the TOP is responsible for directing the BA in this regard.

We also recognize that the BAAL limits defined in the recently approved BAL001-2 ensure that an RE will take all available actions to respond to a
Reportable Balancing Contingency Event and support Interconnection
frequency.
For compliance with Requirement R1 Part 1.1 response is determined by your
ACE within the first 15 minutes regardless of how recovery is accomplished.
Requirement R1 Part 1.3 describes the process for when events combine to
be greater than MSSC and provides exclusion from compliance for Part 1.1.
However, exclusion from compliance for Part 1.1 does not allow an entity to
avoid responding at all to a large event. Note that Part 1.3 does not require
all Contingency Reserves be activated.

For example, using the PJM minimum synchronized reserve requirements
(100% of MSSC, or approximately 1400MW deployed via All-Call) and
regulating reserves (+/- 700MW during peak hours); language that suggests a
mandatory deployment of Contingency Reserve could result in well over
2100MW, responding to a 900MW reportable event. This response could be
much higher since synchronized reserves are typically much greater than the
1400MW requirement and regulation alone could result in 1400MW of
response.

interpreted to mean that an RE shall deploy ALL available Contingency
Reserve, which could be well above MSSC, for ALL Reportable Balancing
Contingency Events which could have an adverse impact on Interconnection
frequency and BES reliability.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

TOP-001-3 R20
TOP-002-2.1b R4, R5, R6, R7, R9 and R10
TOP-002-4 R4
TOP-003-1 R1.2

46

The drafting team agrees the BA is not responsible for determination of
system constraints. However, the following selected list of Requirements
from Standards, either currently enforceable or approved by the NERC Ballot
Body, NERC Board of Trustees and filed at FERC requesting approval for
future enforcement, makes it clear that a Balancing Authority can’t perform
their duties reliably without being knowledgeable of system constraints.

• the Responsible Entity has depleted its Contingency Reserve to a level
below its Most Severe Single Contingency

• utilizing its Contingency Reserve to mitigate an operating emergency
in accordance with its emergency Operating Plan, and

• experiencing a Reliability Coordinator declared Energy Emergency
Alert Level where an energy deficient BA is not able to maintain minimum
Contingency Reserve requirements, and

1.3.1 the Responsible Entity is:

1.3. respond to all Reportable Balancing Contingency Events, which may
include the deployment of Contingency Reserve, however, it is not subject to
compliance with Requirement R1 part 1.1 if:

Accordingly, we propose the changes below.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

47

With the addition of Requirement 3, either R1.2 should be removed from the
standard or the CR Form 1 should be modified to demonstrate Contingency
Reserve restoration including subsequent Balancing Contingency Events that
may occur within the Contingency Event Restoration Period so that
compliance to a Reportable Balancing Contingency Event can be
demonstrated with a single document.
Thank for your suggestion. The SDT believes that compliance with
Requirement R1 and compliance with Requirement R3 are two different

Requirement 3:

R2. Each Responsible Entity shall develop, review and maintain annually, and
implement an Operating Process as part of its Operating Plan to determine
its Most Severe Single Contingency and make preparations to have available
Contingency Reserve equal to, or greater than the Responsible Entity’s Most
Severe Single Contingency. [Violation Risk Factor: Medium] [Time Horizon:
Operations Planning]
The SDT has made this clarifying modification.

We propose the following changes to Requirement 2 to add clarity.

Requirement 2:

Finally, removing the phrase would make a requirement to activate all
Contingency Reserves, regardless of any negative impacts to the Bulk Electric
System for large events. The drafting team discussed this concern and
determined that the BA should only activate the level of reserves that could
be safely used without creating reliability issues on the grid.

TOP-003-3 R2, R4 and R5

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Response:

Answer Comment:

48

EOP-011 states that a Level 2 EEA is "The Balancing Authority is no longer
able to provide its expected energy requirements and is an energy deficient
Balancing Authority." meaning all available resources are in use serving load;
and " An energy deficient Balancing Authority is still able to maintain
minimum Contingency Reserve requirements." which given the first instance
can only be accomplished through arming for load shed to cover the reserves
if a contingency were to occur. In the alternative, this would mean shedding
actual customer load to maintain reserves before the contingency actually
occurs, which is not in the best interest of Reliability.
The SDT disagrees with your comment. EEA Level 3 is titled “Firm Load
interruption is imminent or in progress”. The SDT believes that if an entity is
utilizing firm load for its Contingency Reserve then interruption of firm load is
imminent. Therefore, an entity utilizing firm load for Contingency Reserve
would be in an EEA Level 3.

ISO New England does not agree with the SDT's position that an EEA Level 3
is necessary in order to support an exemption from R1. If this were elevated
to Level 3 that would imply shedding load in order to maintain reserves and
ISO New England understands that this was not the intent.

Kathleen Goodman - Kathleen Goodman On Behalf of: Michael Puscas, ISO New England, Inc., 2 -

Response:

actions. Requirement R1 requires a specific calculation methodology.
Requirement R3 compliance may be demonstrated with various methods.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Answer Comment:

49

1. Definitions – ERCOT reiterates its previous comments regarding the
Reportable Balancing Contingency Event thresholds contained within the
definition of a Reportable Balancing Contingency Event. ERCOT believes that
the introduction of various, differing thresholds creates unnecessary
complexity and would propose a 1000 MW threshold for its interconnection
as such threshold aligns with the current practice. Further, ERCOT reports
other, smaller events to NERC and its Regional Entity through different
mechanisms and, therefore, with differing reporting thresholds, the same
event can be reported to NERC multiple times under different requirements.
Accordingly, since the threshold limits relate only to reporting and associated
documentation, ERCOT respectfully submits that lowering the reportable
event thresholds does not provide any benefit to reliability.
The MW thresholds are based on a statistical evaluation of historical events
in each interconnection and their impact on system frequency. The SDT
utilized conservative numbers in order to provide the System Operators with
the necessary information to operate the grid while maintaining compliance.
Please refer to the Background Document posted with this standard.

ERCOT commends the drafting team on their efforts to improve BAL-0022. However, it has concerns and recommendations regarding the proposed
modifications. ERCOT supports and incorporates into its comments by
reference the comments submitted by the ISO/RTO Council Standards
Review Committee. Additional concerns and recommendations are
described below by Requirement. Proposed revisions are italicized.
Please refer to our response to the ISO/RTO Council Standards Review
Committee, beginning on page. 76.

christina bigelow - Electric Reliability Council of Texas, Inc. - 2 –

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
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50

Each Responsible Entity shall document and implement its criteria for
identification of MSSC and its processes for review of MSSC and for
procurement of contingency reserves greater than or equal to the identified
MSSC, which shall be reviewed no less than annually.

3. Requirement R2 –ERCOT respectfully submits that, as proposed,
Requirement R2 adds potentially onerous and unnecessary administrative
processes and documentation to what has, historically, been a simple, wellestablished process regarding identification of the MSSC and the
procurement of appropriate contingency reserves. To simplify this
requirement while retaining the reliability-related aspects of its objective,
ERCOT offers the following revisions for the SDT’s consideration:

2. ERCOT reiterates the need to revise Requirement 1 to provide
obligations in more direct terms and with additional clarity and reiterates its
comments regarding burdensome and administrative nature of the individual
reporting requirement contained within Requirement R1.2 for individual
Reportable Balancing Contingency Events. Such reporting does not benefit
reliability and could obscure trends or other characteristics that would be
obviated by reporting over a longer time period. Perhaps the SDT could
consider a time period that is shorter than quarterly, but clarify that
reporting is not on an individual basis triggered by individual events.
R1 part 1.2 does not require a report to be submitted. Instead it requires the
calculation to be on the referenced form. This ensures all entities subject to
compliance utilize the same methodology for each event. The SDT disagrees
with the inclusion of a quarterly report in a standard. Adding a requirement
for quarterly or any other time period for reporting would be a Paragraph 81
issue. If NERC or the Regions desire quarterly reporting it should be done
under their data collection process.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

51

ERCOT thanks you for the opportunity to comment upon the proposed

ERCOT suggests this alternative because the identification of MSSC is subject
to criteria and are part of an overall process to be performed. Further, the
proposed requirement presumes a particular structure for responsible
entity’s compliance processes and procedures that designates the “how” of
meeting the requirement instead of the “what.” The proposed revision
preserves the objective of the proposed Requirement 2 while ensuring that
the requirement is results-based and respectful of the various administrative
structures established within various entities to administer compliancerelated documentation and processes.
The SDT does not believe that the requirement is telling an entity how to
comply but rather requiring a process to address the reliability issue.
Also, the SDT has modified the requirement to provide additional clarity.

· Evidence to indicate that the processes have been reviewed and
maintained annually.

• Documentation of its processes for identification of the MSSC and
procurement of contingency reserves equal to or greater than its Most Severe
Single Contingency; and

• Criteria for determination of the MSSC;

M2. Each Responsible Entity will have the following documentation to show
compliance with Requirement R2:

Compliance may be achieved by demonstrating that:

Measure 2 could then be modified as follows:

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Answer Comment:

Ginger Mercier

Mike Brytowski
Bob Solomon

Group Member Name
John Shaver

Group Name:

Ben Engelby - ACES Power Marketing - 6 –

Response:

SERC

MRO
RFC

1,3

1,3,5,6
1

Region Segments
WECC 1,4,5

52

(1)
We applaud the SDT on its efforts to clarify the language of the
standard and respond to our previous comments. We continue to believe
the SDT is heading in the correct direction during the development of this

Entity
Arizona Electric Power Cooperative,
Inc. Southwest Transmission
Cooperative, Inc.
Great River Energy
Hoosier Energy Rural Electric
Cooperative, Inc.
Prairie Power, Inc.

ACES Standards Collaborators - BARC Project

The SDT thanks you for your suggestion. The SDT has developed an
Operating Reserve Guideline approved through the NERC OC. The guideline
document can be found at the following link.
http://www.nerc.com/comm/OC/Pages/Reliability-Guidelines.aspx

Revisions to BAL-002-2. Should the ERO wish to provide additional guidance
regarding the mix or management of Contingency Reserves, it should
consider the development and publication of a Reliability Guideline.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
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53

(3)
Likewise, we wish the SDT would further clarify this standard’s
applicability. We understand the need to address the instance when a BA
fails to meet the membership requirements of a Reserve Sharing Group
(RSG). We recommend that Section 4.1.1.1 should be split as follows,
“4.1.1.1 A Balancing Authority is the Responsible Entity that is not a member
of a Reserve Sharing Group” and “4.1.1.2 A Balancing Authority that is a

The term Responsible Entity is not defined in the glossary and therefore
cannot be used in the definition. The drafting team also believes that the
measurement in MWs is appropriate in that the process uses MWs to
determine the amount of loss for a DCS event. There was no other proposed
means to measure the event so it is unclear what would be measured
without using MWs. For these reasons, the SDT has not made the suggested
changes.

(2)
We are disappointed that the SDT has not responded or addressed
our previous concerns regarding the “Most Severe Single Contingency”
definition. From the definition, we believe the applicability reference should
be removed entirely. We recommend the definition should read “A
Balancing Contingency Event, as identified by the Responsibility Entity and
maintained in its system models, that would result in the greatest loss of
resource output at the time to meet Firm Demand and export obligations,
excluding those export obligations for which Contingency Reserve obligations
are being met by a Sink Balancing Authority.” We also recommend the
removal of the MW measurement, a unit of power, as a Balancing
Contingency Event is a moment in time.

Thank you

standard. However, we still have concerns regarding the language, scope,
and implementation plan.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
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54

The SDT disagrees with removing the language related to changing the
reportable threshold from the definition. Without that language, it would
prohibit any modification from the 80 percent of MSSC. The drafting team
believes that any modification to the reporting threshold must be made prior
to the event, not after the event. In order to determine the appropriate
reportable threshold, documentation is necessary if an entity decides to
change this threshold.

(4)
The SDT needs to address our previous comments regarding the
“Reportable Balancing Contingency Event” definition. We recommend the
removal of “Prior to any given calendar quarter...” from the definition, as it
implies the need for an additional requirement for Responsible Entities to
coordinate an exception from the rest of the definition which is based on a
percentage of the MSSC or an Interconnection-based amount. Furthermore,
we continue to believe that the thresholds in the definition are arbitrary, and
ask that the drafting team provide a technical basis for these values. In many
cases, the values selected are below the median values identified in
Attachment 1 of the background document. By not documenting the more
frequently occurring values annually, we fear this could cause issue later on
in the standard development process. We recommend moving the
identification of these values, and supporting background for their selection,
to an attachment within the standard, similar to the approach taken in NERC
Standard BAL-001-2.

Some RSGs allow for members to participate in the group on an event-byevent basis. As drafted the language is more specific than that proposed.
Therefore, the SDT has not accepted the proposed modification.

member of a Reserve Sharing Group and is the Responsible Entity only in
periods during which the Balancing Authority is not in active status under the
applicable agreement or the governing rules for the Reserve Sharing Group.”

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
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55

(7)
We feel the SDT is overcomplicating the language of Requirement
R1. We concur that clarification is needed in the instance when a Balancing
Contingency Event follows a single Reportable Balancing Contingency

Once the standard is adopted by the NERC BOT, the definitions would be
moved to the NERC Glossary of Terms.

(6)
The SDT should consider moving all standard-specific definitions to
the NERC Glossary of Terms.

There is not an ACE threshold for a reportable event. The reportable event is
established by the amount of the resource loss. As an example, if a runback
occurred and the MW threshold is not reached in a single minute then it
would not be considered a reportable event. Therefore, the start of the
event would be the minute in which the threshold is met not the start of the
runback.

(5) Under certain situations, a Responsible Entity may not be aware of the
significance of a Balancing Contingency Event. For the definition of
Contingency Event Recovery Period, the SDT should clarify that the recovery
period should not start with the initial decline of resource output, but the
instance when ACE reaches the reportable threshold of a Reportable
Balancing Contingency Event and fifteen minutes thereafter.

The reporting thresholds are supported by the referenced background
document. With the reference to the background document, the commenter
should understand that the values are not arbitrary but determined by the
statistical evaluation of historical events. Once the evaluation was done, the
drafting team determined the average of the medians and determined that
the values should be rounded to an even 100 value to make the reporting
threshold easily remembered by operating personnel.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
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56

(9)
We acknowledge the SDT for its response to our previous comments
regarding Requirement R1.2. However, we still feel that a requirement for
documenting events in a spreadsheet is administrative in nature, and could
even be classified as a P81 requirement, as its violation would never result in
a harm to BES reliability, especially at a Medium level risk to operations. If an
entity only identifies the MW loss and date and time of the event, yet leaves
the rest of the form blank, would this result in a violation? As written, the
answer would be no, although an incomplete form would not meet the

The SDT reviewed the VSL and CR Form 1 calculations and find them to be
consistent. Therefore, no changes have been made to either the VSLs or CR
Form 1.

(8)
We have concerns with the VSLs identified for Requirement R1. We
agree with the SDT’s conclusions that the measured contingency reserve
response and required recovery value of Reporting ACE, when is adjusted for
other Balancing Contingency Events that occur during the Contingency Event
Recovery Period, are mathematically equivalent. However, the VSLs are
based on one approach while the spreadsheet is based on the other. We
recommend the SDT select one approach and use it consistently throughout
the standard.

While the SDT understands your concern we do not agree with the desire to
separate this into two requirements. Separation of Requirement R1 into two
requirements would likely cause a violation of one requirement that could
result in violation of both requirements.

Event. However, embedding a reference to identify what is and isn’t
required within the same requirement is cumbersome. We recommend
moving the embedded reference to another requirement and identify the
Contingency Event Recovery Period only applies to a single event.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
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57

For compliance with Requirement R1 Part 1.1 response is determined by your
ACE within the first 15 minutes regardless of how recovery is accomplished.

(10) We recommend the removal of “all Reportable Balancing Contingency
Events” as a condition listed in Requirement R1.3. This condition is already
referenced in R1. We believe rewording Requirement R1.3 to read “…deploy
Contingency Reserve, within system constraints, except when not subject to
compliance with Requirement R1 part 1.1 if…” would still satisfy the
requirement.

The SDT disagrees with moving the criteria to a separate attachment and
having the entities create their own calculation of compliance. This would
put every entity at risk of violation due to the need to support the calculation
made to demonstrate compliance prior to any compliance evaluation. By
providing the form referenced in Requirement R1 Part 1.2, industry
essentially needs to provide one number from the form to prove compliance.

The SDT believes that a form that is partially filled out may be sufficient to
meet compliance with Requirement R1 Part 1.2, although this would depend
on circumstances. However, an incomplete form will show a failure to
correct ACE to its pre-event level which would be a violation of Requirement
R1 Part 1.1.

The SDT disagrees with the characterization that this is a Paragraph 81 issue.
The Requirement R1 part 1.2 requires a specific calculation in the form. This
ensures all entities utilize the same methodology for each event. There is not
a reporting requirement in the standard.

intention of the SDT to provide consistent reporting. We recommend the
SDT identify the criteria needed for uniform reporting in a separate
attachment to the standard and remove administrative tasks that meet
Paragraph 81 criteria.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
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58

(13) We disagree with the VSLs identified for Requirement R3 that measure
the percentage of Contingency Reserve restoration. The requirement
identifies the required time that such restoration must be completed. We
recommend replacing with the form “The Responsible Entity restored less

Thank for your suggestion. The SDT believes that compliance with
Requirement R1 and compliance with Requirement R3 are two different
actions. Requirement R1 requires a specific calculation methodology.
Requirement R3 compliance may be demonstrated with various methods.

(12) If the intent of the SDT to have Responsible Entities use CR Form 1,
then we recommend adding its use in Measure M3 and in the RSAW for
R3. A Responsible Entity is already able to use the form to demonstrate its
deployment of Contingency Reserve, within system constraints, then it
should be able to reuse the form to demonstrate the restoration of
Contingency Reserve within the Contingency Reserve Restoration Period.

The SDT appreciates your comment but believes that use of both words
provides an additional level of clarity. We agree that it is possible to
accomplish both with one action.

Requirement R1 Part 1.3 describes the process for when events combine to
be greater than MSSC and provides exclusion from compliance for Part 1.1.
However, exclusion from compliance for Part 1.1 does not allow an entity to
avoid responding at all to a large event. Note that Part 1.3 does not require
all Contingency Reserves be activated.
(11) In reference to Requirement R2, we question the need to review an
Operating Plan, as such action is already implied with an Entity is
“maintaining” their plan. We believe the language identified should be
aligned with the language listed within NERC Standard EOP-010-1.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

(16)

59

We observe a typographical error within the Implementation Plan

The SDT understand your concern. However, based on our review of the
timing, this is not an issue.

(15) We caution the SDT that references to the term “Reporting Area
Control Error” in the rationale for Requirement R1 goes into effect July 1,
2016. The Implementation Plan references that the standard would go into
effect six months after FERC approval. Since this term is critical to the
definition of “Pre-Reporting Contingency Event ACE Value”, we recommend
an update to the Implementation Plan to July 1, 2016 or later as the effective
date.

The SDT believes the removal of the bullets would require an entity to
recover its ACE within 15 minutes regardless of other events occurring within
that 15 minutes. The SDT also believes that compliance with Requirement R1
and compliance with Requirement R3 are two different actions.
Requirement R1 requires a specific calculation methodology. Requirement R3
compliance may be demonstrated with various methods.

(14) We feel that the bullets of Requirement R1.1 and Requirement R3 are
redundant in reference to “any Balancing Contingency Event that occurs
during the Contingency Event Recovery Period.” We suggest removing the
redundant bullets in Requirement R1.1 for clarity, and instead expand
Requirement R3 to include a reference to magnitude.

The SDT believes that your suggested wording allows unlimited time for an
entity to restore its Contingency Reserve.

than x% but at least y% of required Contingency Reserve following the
conclusion of the Contingency Event Restoration Period.”

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Answer Comment:

Rachel Coyne - Texas Reliability Entity, Inc. - 10 –

Response:

We thank the SDT for this opportunity to comment on this standard.

60

Texas RE noticed the VSL for R2 does not address the review annually portion
of the Requirement. VSL should be changed to include “maintain annually”.

Texas RE noticed the VSL for R1 does not address R1.3. The language for R1.3
should be included.
Requirement R1 Part 1.3 defines exceptions; therefore the SDT does not
believe that it would be appropriate to create a VSL.

(18)

Thank you for your comment. The title was lost during the translation to a
PDF document. The SDT will make the necessary correction.

(17) We recommend the SDT fix the title page of the background
document to include the document’s title, “Disturbance Control Performance
- Contingency Reserve for Recovery from a Balancing Contingency Event
Standard Background Document.”

Thank you. The SDT has made the necessary correction.

regarding the definition of Most Severe Single Contingency. We recommend
the removal of the “that is not part of a Res area” reference. The definition
should then read “…within the Reserve Sharing Group (RSG) or a Balancing
Authority’s area that not part of a Reserve Sharing Group…”

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Answer Comment:

61

Until BAL-001-2 has been fully implemented, data has been collected and
evaluated, it would be difficult to show the reliability impacts of a complete
retirement of BAL-002-1. Further, the team has determined that there is a
reliability gap absent BAL-002-2. Also, through the standard development
process for this project, numerous issues with the current standard have

If the Reportable Disturbance occurs when frequency is above Scheduled
Frequency, as over-response required by the Balancing Authority to ensure
compliance with BAL-002 may cause the Balancing Authority to be above its
high BAAL under BAL-001-2.

Example of loss of generation in the middle of the night:

Now that BAL-001-2 is approved, there will be another standard driving a BA
to take corrective action in certain situations where compliance with BAL-002
may have a detrimental impact on Interconnection frequency.

Mike ONeil - NextEra Energy - Florida Power and Light Co. - 1 –

Response:

Texas RE recommends the VSL for R3 should include Requirement language
“at least its Most Severe Single Contingency”.
The SDT believes that as written (“…required Contingency Reserve…”) the
VSL provides sufficient clarity.

The SDT has modified the lower VSL to clarify that “maintain” meant
“maintain annually”.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Response:

Answer Comment:

62

Until BAL-001-2 has been fully implemented, data has been collected and
evaluated, it would be difficult to show the reliability impacts of a complete
retirement of BAL-002-1. Further, the team has determined that there is a
reliability gap absent BAL-002-2. Also, through the standard development
process for this project, numerous issues with the current standard have
been identified. As such, the proposed standard provides clarity for the
issues that have been identified to date.

Now that BAL-001-2 is approved, there will be another standard driving a
Balancing Authority to take corrective action in certain situations where
compliance with BAL-002 may have a detrimental impact on Interconnection
frequency. One example would be if there is a loss of generation in the
middle of the night. If the Reportable Disturbance occurs when frequency is
above Scheduled Frequency, as over-response by the Balancing Authority to
ensure compliance with BAL-002 may cause the Balancing Authority to be
above its high BAAL under BAL-001-2.

Jennifer Losacco - NextEra Energy - Florida Power and Light Co. - 1 – FRCC-

Response:

been identified. As such, the proposed standard provides clarity for the
issues that have been identified to date.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Answer Comment:

Jamie Lynn Bussin - NaturEner USA, LLC - 5 –

Introduction

63

Balancing Contingency Event: Any single event described in Subsections (A),
(B), or (C) below, or any series of such otherwise single events, with each
separated from the next by one minute or less.

NERC’s suggested changes to BAL-002-2 propose the following definition of
Balancing Contingency Event:

While NaturEner largely supports the proposed changes to BAL-002-2,
NaturEner believes the standard can be, and should be, even further
improved. Specifically, NaturEner recommends that the definition of
“Balancing Contingency Event” should be further modified to explicitly
include as a qualifying event an unpredicted loss of generation
capability. While generator-neutral, the explicit inclusion of this type of
event has particular and extreme importance to variable (i.e., renewable)
generation, which due to the current inherently imprecise nature of
forecasting, unavoidably experience such events at times. The sole reason
that NaturEner has abstained in this balloting process, rather than voting
affirmative, is because NERC’s proposed definition does not explicitly include
as a qualifying event an unpredicted loss of generation capability.

NaturEner USA, LLC and its subsidiaries (“NaturEner”) largely support the
proposed changes to BAL-002-2, which move the standard towards a
performance-based measure of disturbance control response.

I.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Due to
unit tripping,

a.
i.

And, that causes an unexpected change to the responsible entity’s ACE;

b.

unpredicted loss of generation capability.

64

Revising that definition as suggested is consistent with the underlying
reasons for specifying certain events as Balancing Contingency Events, as
NaturEner’s suggested revision reflects sudden and unavoidable events
affecting the grid, and also supports the efficient and effective deployment of
resources and the integration of renewable resources. Moreover on a
broader basis, though such a revision to the definition is not required for

iv.

NaturEner recommends that the definition should be revised to add a fourth
clause to subsection A.a.:

C. Sudden restoration of a Demand that was used as a resource that
causes an unexpected change to the responsible entity’s ACE.

B. Sudden loss of an import, due to unplanned outage of transmission
equipment that causes an unexpected imbalance between generation and
Demand on the Interconnection.

sudden unplanned outage of transmission Facility

iii.

ii. loss of generator Facility resulting in isolation of the generator from the
Bulk Electric System or from the responsible entity’s System, or

Sudden loss of generation:

A.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Reasoning

65

For conventional generating units in the west, there are few limitations on
the cause or frequency of qualifying contingency events. This is consistent
with the underlying purpose and rationale of a reserve sharing group - that
there are various extreme events which are unpredictable, unavoidable, and
can impact reliability. By pooling the resources of participating Balancing

NaturEner takes wind power forecasting extremely seriously, and has
invested significant resources to improve our ability to accurately schedule
our generation onto the grid. However, there are some weather events that
are extremely difficult to forecast and can cause wind generation units to
lose generating capability quickly and unexpectedly. These can result from
events such as a sudden change in wind direction due to changing weather
regimes or localized effects, or from other complex weather interactions
which are not well-captured by state of the art forecasting
techniques. Though these events are outside of our control and can result in
a sudden and large unpredictable loss of generation, such events are
currently not recognized as qualifying events in some regional reserve
sharing groups.

NaturEner collectively is the owner of three wind farms, the Glacier Wind 1
wind farm, the Glacier Wind 2 wind farm, and the Rim Rock wind farm, as
well as two wind-based balancing authorities, NaturEner Power Watch, LLC
and NaturEner Wind Watch, LLC.

II.

reserve sharing groups to include unpredicted loss of generation capability as
a qualifying contingency event under which reserve contingencies can be
called upon, such a revision to the definition can only help ongoing efforts to
encourage reserve sharing groups who have not yet approved such
occurrences as qualifying events to do so now.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
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66

The exclusion of extreme loss of wind or solar events from qualifying
contingency events leads to at least two negative consequences. First,
because the calculation of the resource requirements do not consider
regional diversity, the sum of the resource requirements calculated at each
individual Balancing Authority-level are much larger than what would be
calculated at a system-wide level, leading to systematic overprocurement. Second, due to the increase in capacity resulting from this
approach, wind integration tariffs have been implemented in some Balancing
Authorities, chilling the ability of new renewable generation to come online
in some regions. In contrast, the Midwest ISO has been progressive in
implementing market initiatives and programs to enable flexibility in its
system and has not needed to increase its reserve capacity as its renewable
penetration has increased. The Southwest Power Pool is also a system which
has been recognized as a leader in variable integration, and its reserve
sharing group makes no limitations on what the cause of a qualifying event is,
only that it should be a loss of generation greater than 50 MW. Also with
respect to two different weather-related events which result in a loss of
generation, members of the Northwest Power Pool (NWPP) are currently
allowed to call contingency reserves for high-speed cutouts and for

Authorities, reliability can be maintained without requiring individual
Balancing Authorities to carry 100% of MSSC in reserves. This is beneficial to
the grid, because it avoids costly over-procurement of capacity, while still
ensuring the reliability of the system as a whole. The low likelihood that
multiple contingencies will occur at the same time means that this shared
capacity can be relied upon to be sufficient. Large rapid loss of wind (and
solar) events are similarly consistent with the underlying purpose and
rationale of a reserve sharing group, in that they there are extreme events
which are unpredictable, unavoidable, and can impact reliability. Moreover,
if they are appropriately defined and evaluated over a geographically diverse
area, they are unlikely to occur at the same time.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
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67

The risk of unnecessary reserve build-outs and holdbacks may be alleviated
to some extent if a regional energy imbalance market (“EIM”) is
implemented, because the market would settle every 5 minutes, thereby
resolving the time constraints outlined in our previous comments. However,
RBC will come into effect prior to any operational EIM in the WECC. This may
in fact result in a system-wide increase in capacity required to be held in
reserve and unnecessary reservation of related transmission, and their
associated costs.

With the conversion of BAL-001 to the BAAL standard, the standard approach
of using a “CPS2 Analysis” to determine the reserves required to operate
reliably will become obsolete. At this point, the timing issue which NaturEner
raised in its January 26, 2015 FERC comments to the proposed rulemaking
regarding BAL-001 (FERC 20150126-5252, RM14-10) will become more
important (in fact, FERC in its Order in that RM14-10 proceeding, suggested
that NaturEner raise the subject matter set forth in these comments in this
NERC proceeding (151 FERC ¶ 61,048, at page 26, footnote 72)). In a CPS2
analysis, the monthly ACE is evaluated to ensure that reserves are sufficient
such that 90% of the 10 minute periods are within L10, regardless of the
magnitude. In a BAAL analysis, the ACE will have to be evaluated such that
any single 30 minute period should not exceed the BAAL limits. Due to the
timing constraints of 15 minute scheduling and the 30 minute BAAL timer,
there will be some ACE events which cannot be resolved by modifying
interchange schedules. To ensure that a RBC violation will not occur, BA
reserves will need to be carried which can resolve the largest such event
which could be observed. This will result in an increase in the inefficient
deployment of capacity and related transmission reservations in order to
maintain compliance for unpredicted loss of generation capability events
unless such events qualify as recognized balancing contingency events.

temperature extremes.

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68

For smaller Balancing Authorities such as ours, this is a catch-22. To integrate
our wind with the system, we want (and should want) to participate in the
EIM. However, due to the resource sufficiency requirement, the amount of
reserves that a Balancing Authority would need to carry would remain
unchanged from the current business as usual because the resource
sufficiency requirements still assume the scheduling time frames currently in
place, and does not allow the benefits of diversity to be included in the
assessment of those requirements. For larger Balancing Authorities, this may
not seem to be a problem now, because they may currently have sufficient

Even if and when an EIM is present, however, it still will likely not adequately
resolve the problems from unpredicted loss of generation capability unless
designed appropriately. It may still cause individual Balancing Authorities to
procure more reserve capacity and related transmission than is required to
reliably operate the system as a whole. In discussion regarding
implementation of an EIM, a resource sufficiency (RS) methodology is being
considered by the NWPP to verify that EIM participants enter the scheduling
hour with sufficient resources. The work being done in this respect is
thoughtful and important. However, the efforts currently being considered
also highlight a gap in the existing system in the west. In order to require
that participants come to the market “Firm for the hour”, an analysis of the
error frequency distribution associated with a Balancing Authority is being
done to evaluate error across the next operating hour, using a persistence
forecast from 30 minutes prior to the hour. Required reserve capacity will be
determined based on a selected probability of events which would exceed
that capacity. This work is ongoing, so it is not clear what the final
parameters will be, but a probability of 95% has been examined. This
analysis will be done on a Balancing Authority level (as opposed to a systemside/reserve sharing group level), and the result of this calculation will be the
required reserve capacity needed to allow participation in the EIM.

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69

The impact of calculating a resource sufficiency for an individual site as
opposed to an aggregate system is shown in Figure 3 below. On that chart,

In order to demonstrate the impact of system-wide aggregation on the
reliability of wind generators, the NREL western wind data set [1]from 2006
was used to generate a histogram of the forecast error associated with a
regionally diverse subset of the NWPP member states included in that data
set. The forecast was assumed to be 30 minute persistence, held constant
for the full operating hour. The hysteresis-corrected SCORE value was used
to include the impact of both loss of wind and high speed cutouts. A
comparison of applying this approach to reserve requirements for both an
aggregated 10,000 MW system and an individual 100 MW site are shown in
Figure 1 and Figure 2 below. It can be seen that there is much more volatility
relative to the installed capacity, which is a result of geographical diversity
(i.e., a higher volatility is calculated the smaller the geographic
footprint). Further, it can be seen in Figure 2 below that if the proposed
resource sufficiency approach was applied at an aggregate system level, and
reserve requirements to reach 95% reliability were allocated pro-rata, only
2% of installed capacity would be required. If the individual site level was
evaluated to determine the 95% reliability requirements, then the
requirements would be 8% or installed capacity, or 4 times what is needed by
the system in aggregate. Also note that the NREL data set appears to
underestimate the volatility in in the western region, so the actual realized
requirements are higher than estimated by that approach.

internal diversity and reserves in their own system to cover the current
requirements. However, as load and generation variability continue to
increase, thereby requiring capacity reserves to be increased under the
considered EIM-related reserve requirements, this inefficiency will also
impact those entities, and by extension the cost to the underlying retail
consumer.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
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Recommendations

Sudden loss of generation:
Due to

A.
a.

70

Accordingly, NaturEner requests that NERC revise the definition of “Balancing
Contingency Event” to add a clause iv. to subsection A.a. providing for
unpredicted loss of generation capability, so that that subsection will then
read as follows:

A. Revise the Definition of “Balancing Contingency Event” to Include
Unpredicted Loss of Generation Capability.

NaturEner is extremely appreciative of the work that NERC, WECC, PEAK and
the NWPP are doing to improve the efficiency and reliability of the
grid. Though the issues that we have raised here may have a greater impact
in the near term on smaller Balancing Authorities such ours as compared to
larger balancing authorities, as shown above the issues represent a
detriment to all grid participants and the consumer, an unnecessary and
avoidable hurdle (especially to renewable generation), and an inefficient
allocation of capacity reserves and related transmission.

III.

the x-axis represents the size of the project being evaluated, and the y-axis
represents the resource sufficiency requirements calculated using a 95%
probability. It can be seen that as the installed capacity reaches about 1,000
MW, the required reserves on a system wide level drop to 2-3% of installed
capacity. In the extreme case where the reserves were calculated at the each
individual site level, then the result would be 4 times higher.
Figure 3: Comparison of Reserve Requirement Calculated on Aggregate vs
individual statistics

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

unit tripping,

unpredicted loss of generation capability

iv.

Other Suggested Recommendations.

71

1.
Efforts should be made to encourage regional reserve sharing groups to
allow unpredicted loss of generation capability events as qualifying

In addition to revising the definition of “Balancing Contingency Event“ as
suggested above, NaturEner suggests that NERC’s providing of support and
encouragement for the following considerations wherever appropriate would
also help both alleviate the problems and advance the benefits discussed
above.

B.

The SDT believes that the loss of predicted generation capability does not
impact an entity’s ACE. Therefore, the loss of generation capability does not
require response in a similar manner to loss of generation. In a loss of
renewable generation similar to your example there is no prohibition on the
utilization of Contingency Reserve. A change in ACE from the loss of this
renewable resource would need to be addressed by an entity experiencing a
Reportable Balancing Contingency Event at the same time. As of today, no
one has provided a better reserve requirement than MSSC, therefore this is
the required reserve recommended in this standard.

sudden unplanned outage of transmission Facility, or

iii.

ii. loss of generator Facility resulting in isolation of the generator from the
Bulk Electric System or from the responsible entity’s System,

i.

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72

a.
Failure to do this will result in inefficient and unnecessary acquisition
and deployment of capacity and related transmission.

3.
Resource sufficiency should be evaluated at a system-wide level, as
opposed to at the individual Balancing Authority-level.

a.
Doing so would encourage participation in EIMs, while centralizing the
planning for contingency management.

b. Alternately, the historical contingency events of conventional
generators could be evaluated to provide a benchmark for defining the
allowable frequency of allowable variable generation contingencies.
Unpredicted loss of generation capability does not impact ACE therefore, the
SDT does not agree with your comment. The definition of a Reportable
Balancing Contingency Event takes into account historical events of
conventional generator. To the extent renewable generation loss meets the
definition of Reportable Balancing Contingency Event the SDT does not
believe there is any distinction between renewable generation and
conventional generation. To the extent that the comment looks for the SDT
to advocate for Reserve Sharing Groups to have specific rules, that is a
commercial issue beyond the scope of NERC.
2.
Requirements for resource sufficiency in energy imbalance markets
should be aligned with specified qualifying contingency events in regional
reserve sharing groups.

a.
Qualifying events could be defined using a reasonable persistence
probability of exceedance approach.

contingency events, to the extent events are not already allowed by such
groups.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Answer Comment:

Jared Shakespeare - Peak Reliability - 1 –

Response:

73

The language in R1.1 is confusing with respect to the expectations for
multiple Balancing Contingency Events. Please provide an example of the
required recovery magnitude and timeline of multiple Balancing Contingency
Events.

While the SDT has responded to comments on the term “sudden” by saying
the word does “not need further definition as any definitive definition would
be somewhat arbitrary and possibly ill-fitting for one size entity while
perfectly reasonable for another,” Peak continues to believe that lack of a
clear definition may cause confusion, disagreement and inconsistency.
Absent further clarity in the standard, Peak plans to continue to interpret
“sudden loss of generation” as instantaneous or when the breaker trips.
The SDT understands that different areas of the North American
interconnections handle the definition of “sudden” differently to
accommodate the needs of the area. The SDT felt the definition allowed for
the specific areas to meet their needs within reason. Peak Reliability’s
interpretation works for their needs, however may not work in another area.
Therefore the SDT believes that the definition satisfies the entire NERC body.

Devon Yates, Manager, Operational Analytics, NaturEner USA, LLC

The SDT believes that issues 2 and 3 are commercial in nature and therefore
beyond the scope of this drafting team.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

1. We request clarification on the “system models” information.

Thank you for the opportunity to comment on the draft BAL-002-2 standard. Western Area Power Administration would like to
provide the following comments:

Additional Comments Received from Steve Johnson – Western Area Power Administration

Response:

74

The MW thresholds are based on a statistical evaluation of historical events
in each interconnection and their impact on frequency in that
interconnection. At a high level, the definition of a frequency event in each
interconnection is defined by the frequency impact of an event and the
interconnection characteristics. Please refer to the Background Document
posted with this standard. The SDT utilized conservative numbers in order to
provide the System Operators with the necessary information to operate the
grid while maintaining compliance.

Please provide a technical justification for the varying thresholds in the
different Interconnections. It is unclear why the threshold in the Western
Interconnection would be vastly lower than the threshold in ERCOT or even
than the Eastern Interconnection. For example, there are 50 units with a
PMAX of 500 MW or greater in the Peak RC Area. This is a significant number
that will lead to more DCS events that do not significantly impact reliability
but will distract from other key monitoring activities.

The SDT believes that an entity can utilize CR Form 1 to run different
scenarios, thus providing an entity with examples of the required recovery
magnitudes and timelines for multiple Balancing Contingency Events.

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75

The objective of the BAL-002 standard could arguably be redundant with the contingency reserves inherently required to be compliant with the
BAAL operating criteria. The objective of BAL-002-2 states: "… to assure the Responsible Entity balances resources and demand and returns its
Reporting Area Control Error (ACE) to defined values (subject to applicable limits) following a Reportable Balancing Contingency Event." Without
proper context this objective sounds very similar to the understood objective of the BAAL operating criteria, with two distinct differences: BAL002-2 requires an ACE value return to be performed without any consideration for interconnection health (frequency), and this recovery is

AECI appreciates the drafting team's persistent efforts to further improve BAL-002-2 through standards development. The requirements within
the current revision are an improvement over the currently enforceable BAL-002-1 and previous revisions. However, after considering FERC's
approval of the BAAL operating criteria (BAL-001-2 R2) in Order 810, the reliability benefit, or need, of a BAL-002 standard is no longer apparent.

Additional Comments Received from Phil Hart – Associated Electric Cooperative, Inc.

The normal constraints that are used for determining the limits of the system, including System Operating Limits,
Interconnection Reliability Operating Limits and other pertinent operating limits determined by the Transmission Operator,
Generator Operator, Balancing Authorities and monitored by the Reliability Coordinator(s).

3. In 1.3 its stated “deploy Contingency Reserve, within system constraints.“ We are not sure what is meant by “system constraints” please
clarify.

Under the proposed standard, there is no real-time measurement of Contingency Reserves in R2. Instead, the requirement is for the dayahead Operating Plan to show that there is an expectation that the Responsible Entity will have the necessary Contingency Reserves. The
time frame for this plan is dependent upon the time frame used by the Responsible Entity.

2. We would like to request clarification on the clock-hour language that was included in the R2 rationale, but removed. The focus here is
that we want to make sure the clock-hour average is still how we will be measured and not individual AGC cycle contingency reserves
calculations for carrying sufficient reserves.

System models are those models that are used to plan reliable operation of the interconnection. The models would be used for near-term
(next hour to next week) planning as well as longer term planning. Whether this is a single model used by an entity or multiple models
used by an entity, each of them would be expected to include an evaluation of the entity’s likely contingencies as required under the TPL
standards.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Additional Comments Received from the ISO Standards Review Committee

Until BAL-001-2 has been fully implemented, data has been collected and evaluated, it would be difficult to show the reliability
impacts of a complete retirement of BAL-002-1. Further, the team has determined that there is a reliability gap absent BAL-002-2.
Also, through the standard development process for this project, numerous issues with the current standard have been identified.
As such, the proposed standard provides clarity for the issues that have been identified to date.

The BAL-002 project has been a long one. While the project intent and associated FERC directives may have been applicable during the initial
phases of development, the recent acceptance of the BAL-001-2 and BAL-003-1 standards could warrant the development of an alternate
approach. For instance, a specific definition of the remaining directives and their relationships to BAL-001 and BAL-003 could prove that these
directives have been met. A refocus of the team's effort now, as opposed to later, may be a better use of NERC and industry resources while
also advancing the NERC initiative for Results Based Reliability Standards Development. For this reason, AECI requests that NERC and the
drafting team re-evaluate the reliability risks related to this standard, along with the outstanding FERC directives, to evaluate the need for the
BAL-002 standard.

76

Compliance with BAL-001-2 R2 inherently requires a contingency reserve policy, and will be required continent wide. The unexpected loss of
generation or load is an assumed risk that is taken by Balancing Authorities while striving to meet customers energy demands. They also assume
compliance risks. If an entity does not carry sufficient reserves or has measures in place to import energy (RSG, interchange transactions, etc)
prior to an event occurring, AND their lack of response in a timely fashion creates a negative impact to the Bulk Electric System, they will be in
violation of the BAL-001-2 standard. To mitigate this compliance risk, entities MUST carry contingency reserves. If they do not then they will
eventually violate BAL-001-2 R2. If they do not violate BAL-001-2, then no real risk to reliability was imposed on the system and any requirement
that determined a non-reliability related event as a violation would prove itself to be non-risk based.

By imposing additional requirements above and beyond BAL-001-2, the BAL-002 standard can negatively affect reliability by forcing entities to
disregard the frequency of the interconnection and respond with corrective action that would push interconnection frequency further from
schedule. Standards requirements should not require "backup" standards requirements, these requirements mandate to entities "how" they
must comply with another standard and only create regulatory burden for entities.

required to be 15 minutes instead of 30 (which the 10 year field trial found to be a reliable time period for recovery). These differences do not
mitigate any additional risks to the system, rather they create additional risks to the system.

Provide the risk based parameters (ACE range, Recovery period, Restoration period) for responding to a Balancing Contingency Event
(BCE);
Ensure that the definition of Most Severe Single Contingency (MSSC) does not include more than one resource;
Ensure that the definition of BCE does recognize the possibility of the loss of more than one resource;
Eliminate draft 6’s hourly obligations; and
Clarify that shedding load is not an expected action in order to maintain reserves.

Links MSSC to BCE; and
Links Contingency Reserves (CR) to Disturbance Control Standard (DCS) compliance.

Balancing Contingency Events;
MSSC;
Contingency Event Recovery Period; and
The EEA level referenced in R1.3.1

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
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77

The SRC has characterized its comments in three classifications: those proposed to facilitate clarity; those proposed to ensure that the focus of
requirements remains on reliability; and those proposed to address other concerns.

For compliance with Requirement R1 Part 1.1 response is determined by your ACE within the first 15 minutes regardless of how
recovery is accomplished. Requirement R1 Part 1.3 describes the process for when events combine to be greater than MSSC and
provides exclusion from compliance for Part 1.1. However, exclusion from compliance for Part 1.1 does not allow an entity to
avoid responding at all to a large event. Note that Part 1.3 does not require all Contingency Reserves be activated.

The SRC again asks the SDT to remove the language within draft 7’s proposed CR requirement that ties DCS compliance to the use of CR.

x
x
x
x

The SRC proposes clarifying modifications to definitions for:

x
x

The SRC does not agree with proposed standard wording that:

x
x
x
x

x

The SRC agrees with the intention of the SDT draft 7 posting to:

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
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1.2. document all Reportable Balancing Contingency Events using CR Form 1.

ͻŝƚƐWƌĞ-Reporting Contingency Event ACE Value (if its Pre-Reporting Contingency Event ACE Value was negative); however,
any Balancing Contingency Event that occurs during the Contingency Event Recovery Period shall reduce the required
recovery: (i) beginning at the time of, and (ii) by the magnitude of, such individual Balancing Contingency Event.

or,

78

1.1.within the Contingency Event Recovery Period, demonstrate recovery by returning its Reporting ACE to at least the recovery value
of:
ͻnjĞƌŽ;ŝĨŝƚƐWƌĞ-Reporting Contingency Event ACE Value was positive or equal to zero); however, any Balancing Contingency
Event that occurs during the Contingency Event Recovery Period shall reduce the required recovery: (i) beginning at the time
of, and (ii) by the magnitude of, such individual Balancing Contingency Event,

R1. The Responsible Entity experiencing a Reportable Balancing Contingency Event shall:

1. Retaining current draft language:

x Requirement R1.1 defines the target ACE correction (range of recovery);
x Requirement R1.3 defines Contingency Reserve deployment;
x Sub-Requirements of R 1.3 then introduce exceptions for R1.1 (i.e., R 1.3.1 and R 1.3.2).
This organization does not allow readers and entities responsible for compliance and direct correlation between specific defined obligations
and the proposed exemptions. To facilitate clarity, the SRC offers two recommendations. The first recommendation preserves much of the
current, draft language while the second recommendation provides more streamlined language:

In particular, the SRC suggests that the linkage between R 1.1 and R1.31 is a source of ambiguity within the standard because:

The SRC would ask that the SDT to redraft the requirements in more direct terms. Phrases like “demonstrate recovery” in the requirement
section of the standard can be construed ambiguously and a clear reliability requirement omits unnecessary words and directly defines the
obligation.

Revisions Proposed To Facilitate Clarity

multiple Contingencies where the combined MW loss exceeds its Most Severe Single Contingency and that are
defined as a single Balancing Contingency Even;, or
multiple Balancing Contingency Events within the sum of the time periods defined by the Contingency Event
Recovery Period and Contingency Reserve Restoration Period whose combined magnitude exceeds the
Responsible Entity's Most Severe Single Contingency.

79

Zero within the Contingency Event Recovery Period if the Responsible Entity’s Pre-RBCE ACE Value were positive or equal
to zero; or
Its Pre-RBCE ACE Value if the Responsible Entity’s Pre-RBCE ACE Value were negative

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

x

x

R1.
Unless the Responsible Entity is experiencing any Reliability Coordinator-declared Energy Emergency Alert Level 1 or higher, is utilizing
its Contingency Reserve to mitigate an operating emergency in accordance with its emergency Operating Plan, or has depleted its Contingency
Reserve to a level below its Most Severe Single Contingency, , the Responsible Entity experiencing a Reportable Balancing Contingency Event
(RBCE) shall return its ACE to:

ͻ

ͻ

x the following subsequent event(s) occur:
1.3.2 the Responsible Entity experiences:

the responsible entity:
ͻ is experiencing any Reliability Coordinator-declared Energy Emergency Alert Level 1 or higher; is utilizing its
Contingency Reserve to mitigate an operating emergency in accordance with its emergency Operating Plan; or
has depleted its Contingency Reserve to a level below its Most Severe Single Contingency .

2. More direct version:

or,

x

Unless:

1.3. deploy Contingency Reserve, within system constraints, to respond to all Reportable Balancing Contingency Events,
however, it is not subject to compliance with Requirement R1 part 1.1 if: 1.3.1 the Responsible Entity is:

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80

The SRC does recognize the SDT’s attempt to address the issue of maintaining reserves designed to preserve serving load verses the issue of
shedding load to preserve reserves and that it makes no sense to shed load to maintain reserves that are designed to protect load from being
shed. Additionally, the SRC questions the need for the proposed Requirement R2 (i.e., the requirement to have a method to compute MSSC).

The drafting team’s main focus is on reliability and as drafted, states the requirement but does not define how an entity must accomplish the
goal. For example, the requirements do not require the use of Contingency Reserve for a measured Reportable Contingency Reserve Event.
The measurement is only based on the ACE value within 15 minutes from the time of the event. The only area where there is a required use of
Contingency Reserves is for events that exceed an entity’s Most Severe Single Contingency. In these cases, there should not be an expectation
that a system operator need do nothing since the event is not going to be subject to mandatory compliance. Instead, the expectation should
be that the operator will address the imbalance created to a reasonable extent through the use of deliverable Contingency Reserves without a
requirement to fully restore ACE to any specific level.

The SRC asserts that the primary focus of BAL-002 should be reliability (ACE recovery) with less focus be given to the specific process regarding
how to meet the reliability requirement. The current draft appears to link economic sharing arrangements (Contingency Reserves) to a
reliability requirement and, therefore, precludes the use of more effective processes to meet the reliability requirement. The SRC cautions the
SDT against mandating the use of a process where such usage would be inappropriate from both a reliability and cost efficiency perspective
when other processes are available For example, as written, draft 7 could preclude the use of Demand Side Management (DSM) as
Contingency Reserves (in contradiction of Order 1000), and restricting DSM to Emergencies only. For these reasons, the requirements should
be re-focused on what needs to occur for reliability – not how such activities are performed.

Revisions proposed to ensure that the focus of requirements remains on reliability

The drafting team appreciates the commenters effort to make the language clearer. The SDT believes that the existing format provides the
clarity needed withal details. The proposed eliminations and reformatting does not accomplish the SDT’s intent. The proposed EEA level is
unsupportable. According to the definitions of the EEA levels, there is no acceptable reason to excuse performance for an entity in an EEA Level
1. According to the definition of the EEA Level 1, an entity should have all necessary contingency reserves. Therefore the entity should respond
according to R1 and correct their ACE within the Disturbance Recovery Period.

Where a Balancing Contingency Event exceeds the responsible entity’s MSSC or multiple Balancing Contingency Events occur
within the Contingency Event Restoration period of the 1st RBCE, the responsible entity shall deploy contingency reserves, but
such response shall not be subject to Requirement R1:

x
x
x

develop a plan to explain how to compute MSSC and review that plan every year
implement the computation ( the implication is that the plan will introduce the time frame for updating MSSC)
carry an equivalent amount of RC (for as long as the plan states)

an annual obligation to compute MSSC and to use that annually-computed MSSC in system operations, and
carry an equivalent amount of reserves for that year

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
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81

The drafting team believes that the Operating Process developed by the Responsible Entity would address these concerns related to potential
ambiguity. The drafting team understands that it is possible, although somewhat unlikely for an entity to have an MSSC that does not change
during the course of an operating year for several reasons. However, the drafting team does not believe that this is an issue in the standard.
Rather it is an issue that entities need to address as part of the required Operating Process. As an example, an entity may determine that the
largest loss it could ever expect would be 1,000 MW so that is the level they will carry at all times, regardless of their real-time number being
lower on any given day. This would be a means to ensure that compliance with R1 would not be an issue, although arguably it may not be very
efficient. Another entity could decide that the loading of a transmission line far exceeds the size of the largest generator so they would plan to
forecast the line loading and set a floor for their Contingency Reserves equal to the size of their largest generator, thus allowing the MSSC to
fluctuate each hour in their Operating Plan. However, in both cases, the real-time number will drive compliance with R1. Therefore, the drafting
team believes that the proposed definitions and requirements address appropriately the possible operational practices.

The definition of MSSC is axiomatic and does not require a formal procedure. The only plausible justification for having such a plan is mandate
self-imposed rules regarding when to compute MSSC; how to apply that calculation; and for how long. Given the ambiguity in draft 7’s R2, either
approach can be justified. Such ambiguity would not serve reliability. As an example, if draft 7 really did intend linking MSSC to an annual value,
and in doing so lock-in a minimum reporting value (80% of MSSC), then what could occur is that small BAs can have a minimum reportable value
that is larger than any unit that is operating on a given day – in effect - exempting them from ever reporting. On the other hand, if draft 7 really
did intend to provide flexibility to the BAs, a number of questions arise: Is this a daily scheduling function, or a continuous operating function? Is
the objective fixed or does it depend on what is operating at the given time? Accordingly, the current approach could be interpreted broadly
and variably and should be revised as it does not appear to be directly focused on or facilitating reliability.

or

x
x

Such requirement is administrative in nature as it mandates a creation of a procedure, an implementation process for that procedure, as well
as a mandate to “have” a market service to calculate MSSC. The sentence in draft 7 can be read as ether:

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2. The standard has a reporting requirement, but does not include a reporting timeframe. Therefore, the most conservative assumption
would be that reporting is on and “individual event” basis. For draft 7, the SDT rejected quarterly reporting based on a non-relevant
paragraph in Order 693.

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Finally, removing the phrase would make a requirement to activate all Contingency Reserves, regardless of any negative impacts to the Bulk
Electric System for large events. The drafting team discussed this concern and determined that the BA should only activate the level of reserves
that could be safely used without creating reliability issues on the grid.

TOP-001-3 R20
TOP-002-2.1b R4, R5, R6, R7, R9 and R10
TOP-002-4 R4
TOP-003-1 R1.2
TOP-003-3 R2, R4 and R5

The drafting team agrees the BA is not responsible for determination of system constraints. However, the following selected list of Requirements
from Standards, either currently enforceable or approved by the NERC Ballot Body, NERC Board of Trustees and filed at FERC requesting
approval for future enforcement, makes it clear that a Balancing Authority can’t perform their duties reliably without being knowledgeable of
system constraints.

1. Delete the phrase “within system constraints” in Requirement R1. Because BAs are not responsible for system constraints (that’s the
role of TOP), the inclusion of this phrase connotes that a BA can be held responsible for exacerbating a SOL problem, even if the BA had
no knowledge of the limit and was taking actions to comply with its obligations. The requirements should respect current roles and
responsibilities of the various functions and, currently, the TOP is responsible for directing the BA in this regard.

The SRC suggests the following comments and/or revisions for the SDT’s consideration:

Revisions Proposed to Address Other Concerns

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Most Severe Single Contingency (MSSC): The Balancing Contingency Event, due to a single contingency as identified and
maintained in the system models within the Reserve Sharing Group (RSG) or a Balancing Authority’s area that is not part of a
Reserve Sharing Group, that would result in the greatest loss (measured in MW) of resource output used by the RSG or a

Draft 7 definition of MSSC:

83

3. The Draft 7 definitions of MSSC and BCE do not resolve the issue of BCE being greater than the MSSC because Draft 7 continues to link
the definitions of MSSC and BCE. The SRC believes MSSC is an a priori / actual state value while BCE is an a posteriori event/experience.
The SRC agrees with the SDT that MSSC can never be more than one resource otherwise it would not be a “single contingency.” BCE on
the other hand can (as the current definition indicates) include the impacts of the loss of more than one resource. To address this
concern, the SRC offers the following comments and revisions.

R1 part 1.2 does not require a report to be submitted to any entity, only to “document all Reportable Balancing Contingency Events” in a
manner that ensures consistency. It requires the documentation of an entity’s restoration of ACE be on the referenced form to
demonstrate that the entity did restore its ACE as required. This ensures all entities utilize the same methodology for each event. Refer
to the measurement for R1 to see that the form is used to calculate the response, not to report anything to NERC or a Regional Entity.
The drafting team did not put a requirement into the standard that an entity report a failure as this is a compliance issue and should not
be part of a reliability standard.

The SRC requests that the SDT explain its correlation between the reporting requirement and P 354 and requests that the SDT clarify the
timing of any required reporting. Additionally, the SRC is unclear as to how “the VSL levels developed were likely to place smaller BA’s
and RSGs in a severe violation regardless of the size of the failure.” Upon review, it appears that values for entities are calculated on a %
of recovery whether applied to an individual event or quarterly performance – accordingly the severity of a violation would still be
correlated to overall performance for some time period. The SRC requests that the SDT re-evaluate its explanation and provide
additional clarification.

354. First, the Commission directs the ERO to develop a modification to the Reliability Standard requiring that any single
reportable disturbance that has a recovery time of 15 minutes or longer be reported as a violation of the Disturbance Control
Standard. This is consistent with our position in the NOPR and NERC’s position in response to the Staff Preliminary Assessment
of the Requirements in BAL-002-0, and was not disputed or commented upon by any NOPR commenters.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

84

Given the above definitions, the SRC concludes that the SDT correctly wants to ensure that MSSC include large interchange schedule
imports as well as large generators. The definition of BCE does that (see sub item B). The draft 7 definition of MSSC relies on the
definition of BCE to ensure that such interchange gets considered. The problem is that the foreword of the BCE definition includes the
phrase “or any series of such otherwise single events.” That addition makes it virtually impossible to quantify / limit one single resource
amount for an MSSC.

C. Sudden restoration of a Demand that was used as a resource that causes an unexpected change to the responsible entity’s
ACE.

B. Sudden loss of an import, due to unplanned outage of transmission equipment that causes an unexpected imbalance
between generation and Demand on the Interconnection.

b. And, that causes an unexpected change to the responsible entity’s ACE;

iii. sudden unplanned outage of transmission Facility;

ii. loss of generator Facility resulting in isolation of the generator from the Bulk Electric System or from the
responsible entity’s System, or

i. unit tripping,

a. Due to

A. Sudden loss of generation:

Any single event described in Subsections (A), (B), or (C) below, or any series of such otherwise single events, with each
separated from the next by one minute or less.

Draft 7 definition of Event:

Balancing Authority that is not participating as a member of a RSG at the time of the event to meet Firm Demand and export
obligation (excluding export obligation for which Contingency Reserve obligations are being met by the Sink Balancing
Authority).

Changes the MSSC definition from being linked to a Balancing Contingency Event of undefined size, to linking MSSC to an
easily identified single resource capacity/expectation.
Can be used to provide clarity concerning why and how the amount of CR can be set to a daily MSSC; and how and why
every CBE can be “reported” upon without being subject to the DCS objectives for an MSSC.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Draft 7 definition of Contingency Reserves

85

The Draft 7 definition CR does not define what CR is, but rather defines what CR may be used for. Moreover, the definition’s use of the
phrase “provision of capacity” requires further explanation to clearly delineate between the concept of “provision of capacity” in the
Operating Planning environment (meaning to request that resource be made available to serve load) versus the “provision of capacity”
in the compliance/operating environment (meaning the amount of energy that was produced at the request of the BA). An additional
issue with the first sentence is that, as written, it specifically excludes the use of those reserves to serve firm customer load. To address
this concern, the SRC offers the following comments and revisions.

The definition of MSSC states “due to a single contingency” and identified in the system models. The phrase “any series of such
otherwise single events” is utilized for recovery measurement, not establishment of Most Severe Single Contingency. However, in actual
operation, there can be events that are nearly simultaneous. In order to clarify that these events could be considered a single Balancing
Contingency Event, the definition of Balancing Contingency Event provides for this. However, the Reportable Balancing Contingency
Events are limited to the size of the identified MSSC.

x

x

This revision:

MSSC is the MW capacity of the single largest resource scheduled to operate for a given day’s peak load. The resource may be a
generator (Maximum Continuous Operating Capacity) or a Firm Interchange scheduled import.

The SRC would suggest that Draft 7 definition of Event be retained, but that the definition of MSSC be redrafted. The SRC suggests:

Reserves were linked to day ahead scheduling in the sense that “reserve” capacity over and above the capacity scheduled to
meet a peak load. This concept was referenced in the original Policy 1 – Generation Control and Performance, (dated Feb 1,
1997) at romanette (i) If CR were viewed as scheduled available system capacity there would be no issue, because then the
measurement of reserves would be focused on the planned capacity for the day. Once that capacity is synchronized it can be
used for any and all purposes.

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

The drafting team believes that the definition of Contingency Reserves is clear as proposed.

http://www.nerc.com/comm/OC/Pages/Reliability-Guidelines.aspx

To the extent that this comment is looking for clarity of all types of reserves and how they interact, please refer to NERC’s Reliability
Guideline: Operating Reserve Management, available on NERC’s website under the Operating Committee “Reliability Guidelines” link
listed under the Committee Resources. The document was originally developed by the drafting team and approved by the NERC
Operating Committee in 2013. A link to this page is provided below.

x

86

The SRC suggests that the issue of CR and reserves in general requires an Industry-wide review; and the SDT in its introduction to its
Response to Comments propose the ERO conduct such a review prior to making a decision on a final ballot. The review would be used to
decide if:

ͻŝƐƵƚŝůŝnjŝŶŐŝƚƐŽŶƚŝŶŐĞŶĐLJZĞƐĞƌǀĞƚŽŵŝƚŝŐĂƚĞĂŶŽƉĞƌĂƚŝŶŐĞŵĞƌŐĞŶĐLJŝŶĂĐĐŽƌĚĂŶĐĞǁŝƚŚŝƚƐĞŵĞƌŐĞŶĐLJKƉĞƌĂƚŝŶŐ
Plan.

ͻŝƐĞdžƉĞƌŝĞŶĐŝŶŐĂZĞůŝĂďŝůŝƚLJŽŽƌĚŝŶĂƚŽƌĚĞĐůĂƌĞĚŶĞƌŐLJŵĞƌŐĞŶĐLJůĞƌt level, and

Draft 7 definition of Contingency Reserve: The provision of capacity that may be deployed by the Balancing Authority to
respond to a Balancing Contingency Event and other contingency requirements (such as Energy Emergency Alerts as specified in
the associated EOP standard). A Balancing Authority may include in its restoration of Contingency Reserve readiness to reduce
Firm Demand and include it if, and only if, the Balancing Authority:

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Figure 1: Histogram Comparing 30 minute ahead Persistence Forecast Error Distribution from NREL data set

Supporting Diagrams Submitted by Jamie Lynn Bussin – NaturEner

87

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

Figure 2: Cumulative Histogram Comparing 30 minute ahead Persistence Forecast Error Distribution from NREL data set

88

Consideration of Comments | Project 2010-14.1 Phase 1 of BARC BAL-002-2
September 29, 2015

End of Report

Figure 3: Comparison of Reserve Requirement Calculated on Aggregate vs individual statistics

89

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

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
(Describe the type of action associated with this posting, such as 30-day informal comment
period, 45-day formal comment period with parallel ballot, 45-day formal comment period with
parallel additional ballot, final ballot.)

Completed Actions

Date

The SAR for Project 2007-18, Reliability Based Controls, was posted
for a 30-day formal industry comment period.

May 15, 2007

The SAR for Project 2007-05, Balancing Authority Controls, was
posted for a 30-day formal industry comment period.

July 3, 2007

A revised SAR for Project 2007-05, Reliability Based Controls, was
posted for a second 30-day formal industry comment period.

September 10, 2007

The Standards Committee approved Project 2007-18, Reliability
Based Controls, to be moved to standard drafting.

December 11, 2007

The Standards Committee approved Project 2007-05, Balancing
Authority Controls, to be moved to standard drafting.

January 18, 2008

The Standards Committee approved the merger of Project 2007-05,
Balancing Authority Controls, and Project 2007-18, Reliability-based
Control, as Project 2010-14, Balancing Authority Reliability-based
Controls.

July 28, 2010

The NERC Standards Committee approved breaking Project 2010-14,
Balancing Authority Reliability-based Controls, into two phases and
moving Phase 1 (Project 2010-14.1, Balancing Authority Reliabilitybased Controls – Reserves) into formal standards development.

July 13, 2011

The draft standard was posted for 30-day formal industry comment
period.

June 4, 2012

The second draft standard was posted for 45-day formal industry
comment period and initial ballot.

March 12, 2013

The third draft standard was posted for 45-day formal industry
comment period and additional ballot.

August 2, 2013

Posting #7 of Standard BAL-002-2: September 2015

Page 1 of 16

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

The fourth draft standard was posted for 45-day formal industry
comment period and additional ballot.

October 28, 2013

The fifth draft standard was posted for a 45 day formal industry
comment period and additional ballot.

August 20, 2014

The sixth draft standard was posted for a 45-day formal industry
comment period and additional ballot.

January 29, 2015

The seventh draft standard was posted for a 45-day formal industry
comment period and additional ballot.

July 7, 2015

Anticipated Actions

Date

Final ballot

September 2015

NERC Board adoption

November 2015

Posting #7 of Standard BAL-002-2: September 2015

Page 2 of 16

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

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:
Balancing Contingency Event: Any single event described in Subsections (A), (B), or (C) below,
or any series of such otherwise single events, with each separated from the next by one minute
or less.
A. Sudden loss of generation:
a. Due to
i. unit tripping,
ii. loss of generator Facility resulting in isolation of the generator from the
Bulk Electric System or from the responsible entity’s System, or
iii. sudden unplanned outage of transmission Facility;
b. And, that causes an unexpected change to the responsible entity’s ACE;
B. Sudden loss of an import, due to unplanned outage of transmission equipment that
causes an unexpected imbalance between generation and Demand on the
Interconnection.
C. Sudden restoration of a Demand that was used as a resource that causes an unexpected
change to the responsible entity’s ACE.
Most Severe Single Contingency (MSSC): The Balancing Contingency Event, due to a single
contingency identified using system models maintained within the Reserve Sharing Group
(RSG), or a Balancing Authority’s area that is not part of a Reserve Sharing Group, that would
result in the greatest loss (measured in MW) of resource output used by the RSG or a Balancing
Authority that is not participating as a member of a RSG at the time of the event to meet Firm
Demand and export obligation (excluding export obligation for which Contingency Reserve
obligations are being met by the Sink Balancing Authority).
Reportable Balancing Contingency Event: Any Balancing Contingency Event occurring within a
one-minute interval of an initial sudden decline in ACE based on EMS scan rate data that results
in a loss of MW output less than or equal to the Most Severe Single Contingency, and greater
than or equal to the lesser amount of: (i) 80% of the Most Severe Single Contingency, or (ii) the
amount listed below for the applicable Interconnection. Prior to any given calendar quarter,
the 80% threshold may be reduced by the responsible entity upon written notification to the
Regional Entity.
x

Eastern Interconnection - 900 MW

x

Western Interconnection – 500 MW

Posting #7 of Standard BAL-002-2: September 2015

Page 3 of 16

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

x

ERCOT – 800 MW

x

Quebec – 500 MW

Contingency Event Recovery Period: A period that begins at the time that the resource output
begins to decline within the first one-minute interval of a Reportable Balancing Contingency
Event, and extends for fifteen minutes thereafter.
Contingency Reserve Restoration Period: A period not exceeding 90 minutes following the end
of the Contingency Event Recovery Period.
Pre-Reporting Contingency Event ACE Value: The average value of Reporting ACE, or Reserve
Sharing Group Reporting ACE when applicable, in the 16-second interval immediately prior to
the start of the Contingency Event Recovery Period based on EMS scan rate data.
Reserve Sharing Group Reporting ACE: At any given time of measurement for the applicable
Reserve Sharing Group (RSG), the algebraic sum of the ACEs (or equivalent as calculated at such
time of measurement) of the Balancing Authorities participating in the RSG at the time of
measurement.
Rationale for Contingency Reserve Definition: Originally a waiver of the R3
Contingency Reserve Restoration requirement was proposed in the event of an
Energy Emergency Alert (EEA). This was predicated on a definition of Contingency
Reserve that did not include readiness to reduce Firm Demand during the
Contingency Reserve Restoration Period during an EEA and on concern that the
attempt to restore Contingency Reserve during an EEA could result in actual
curtailment of Firm Demand in order to free up generation not to be used but merely
to be counted as restored Contingency Reserve when no other Balancing Contingency
Event arose. As an alternative to waiving R3, and to remedy the concern, readiness to
reduce Firm Demand during the Contingency Reserve Restoration Period during an
EEA was proposed for inclusion in the definition of Contingency Reserve as it would
make Firm Demand merely ready to be curtailed in case another Contingency arose
during an EEA.
Readiness to reduce Firm Demand here is a way of providing Contingency Reserves
exclusively when the Responsible Entity is in a Contingency Reserve Restoration
Period during an emergency. Readiness means the Responsible Entity is prepared to
reduce Firm Demand to mitigate events which may increase demand or reduce supply
causing unacceptable risk. The Responsible Entity should have processes and

Posting #7 of Standard BAL-002-2: September 2015

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BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

procedures for direct control over the Firm Demand in place for it to be considered
Contingency Reserves prior to the event.
Contingency Reserve: The provision of capacity that may be deployed by the Balancing
Authority to respond to a Balancing Contingency Event and other contingency requirements
(such as Energy Emergency Alerts as specified in the associated EOP standard). A Balancing
Authority may include in its restoration of Contingency Reserve readiness to reduce Firm
Demand and include it if, and only if, the Balancing Authority:
x

is experiencing a Reliability Coordinator declared Energy Emergency Alert level, and

x

is utilizing its Contingency Reserve to mitigate an operating emergency in
accordance with its emergency Operating Plan.

Posting #7 of Standard BAL-002-2: September 2015

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BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

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: Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event

2.
3.

Number: BAL-002-2
Purpose: To ensure the Balancing Authority or Reserve Sharing Group balances
resources and demand and returns the Balancing Authority's or Reserve Sharing
Group's Area Control Error to defined values (subject to applicable limits) following a
Reportable Balancing Contingency Event.

4.

Applicability:
4.1. Responsible Entity
4.1.1. Balancing Authority
4.1.1.1.
A Balancing Authority that is a member of a Reserve
Sharing Group is the Responsible Entity only in periods during
which the Balancing Authority is not in active status under the
applicable agreement or governing rules for the Reserve Sharing
Group.
4.1.2. Reserve Sharing Group

5.

Effective Date: See the Implementation Plan for BAL-002-2.

6.

Background:
Reliably balancing an Interconnection requires frequency management and all of its
aspects. Inputs to frequency management include Tie-Line Bias Control, Area Control
Error (ACE), and the various Requirements in NERC Resource and Demand Balancing
Standards, specifically BAL-001-2 Real Power Balancing Control Performance and BAL003-1 Frequency Response and Frequency Bias Setting.

B. Requirements and Measures

Posting #7 of Standard BAL-002-2: September 2015

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BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

Rationale for Requirement R1: Requirement R1 reflects the operating principles first
established by NERC Policy 1 (Generation Control and Performance). Its objective is to
assure the Responsible Entity balances resources and demand and returns its Reporting
Area Control Error (ACE) to defined values (subject to applicable limits) following a
Reportable Balancing Contingency Event. It requires the Responsible Entity to recover
from events that would be less than or equal to the Responsible Entity’s MSSC. It
establishes the amount of Contingency Reserve and recovery and restoration timeframes
the Responsible Entity must demonstrate in a compliance evaluation. It is intended to
eliminate the ambiguities and questions associated with the existing standard. In
addition, it allows Responsible Entities to have a clear way to demonstrate compliance
and support the Interconnection to the full extent of its MSSC.
Requirement R1 does not apply when an entity experiences a Balancing Contingency
Event that exceeds its MSSC (which includes multiple Balancing Contingency Events as
described in R1 part 1.3.2 below) because a fundamental goal of the SDT is to assure the
Responsible Entity has enough flexibility to maintain service to Demand while managing
reliability. The SDT’s intent is to eliminate any potential overlap or conflict with any other
NERC Reliability Standard to eliminate duplicative reporting, and other issues.
Commenters suggested a Quarterly Compliance similar to the current reports sent to
NERC. The drafting team attempted to draft measurement language and VSL’s for
quarterly monitoring of compliance to R1. But the drafting team found that the VSL levels
developed were likely to place smaller BA’s and RSGs in a severe violation regardless of
the size of the failure. Therefore, the drafting team has not adopted a quarterly
compliance calculation. Also, the proposed requirement and compliance process meets
the directive in Paragraph 354 of Order 693.
Finally, commenters have suggested that the language in R1 part 1.3 be changed to
specifically state under which EEA level the exclusion applies. The drafting team disagrees
with this proposal. NERC is in the process of changing the EEA levels and what is expected
in each level. The current EEA levels suggest that when an entity is experiencing an EEA
Level 2 or 3 it is short of Contingency Reserves as normally defined to exclude readiness
to curtail a specific amount of Firm Demand. Under the proposed EEA process, this would
only be during an EEA Level 3. In order to reduce the need for consequent modifications
of the BAL-002 standard, the drafting team has developed the proposed language in
Requirement 1 Part 1.3.1 such that it addresses both current and future EEA process. In
addition, the drafting team has added some clarifying language to 1.3.1 since comments
were presented in previous postings expressing a concern only a Balancing Authority may
request declaration of an EEA and a RSG cannot request an EEA. The standard drafting
team’s intent has always been if a BA is experiencing an EEA event under which its
contingency reserve has been activated, the RSG in which it resides would also be
considered to be exempt from R1 compliance.

Posting #7 of Standard BAL-002-2: September 2015

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BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

R1.

The Responsible Entity experiencing a Reportable Balancing Contingency Event shall:
[Violation Risk Factor: Medium] [Time Horizon: Real-time Operations]
1.1. within the Contingency Event Recovery Period, demonstrate recovery by
returning its Reporting ACE to at least the recovery value of:
x

zero (if its Pre-Reporting Contingency Event ACE Value was positive or equal
to zero); however, any Balancing Contingency Event that occurs during the
Contingency Event Recovery Period shall reduce the required recovery: (i)
beginning at the time of, and (ii) by the magnitude of, such individual
Balancing Contingency Event,

or,
x

its Pre-Reporting Contingency Event ACE Value (if its Pre-Reporting
Contingency Event ACE Value was negative); however, any Balancing
Contingency Event that occurs during the Contingency Event Recovery Period
shall reduce the required recovery: (i) beginning at the time of, and (ii) by the
magnitude of, such individual Balancing Contingency Event.

1.2. document all Reportable Balancing Contingency Events using CR Form 1.
1.3. deploy Contingency Reserve, within system constraints, to respond to all
Reportable Balancing Contingency Events, however, it is not subject to
compliance with Requirement R1 part 1.1 if:
1.3.1 the Responsible Entity:
x

is a Balancing Authority experiencing a Reliability Coordinator declared
Energy Emergency Alert Level or is a Reserve Sharing Group whose
member, or members, are experiencing a Reliability Coordinator
declared Energy Emergency Alert level, and

x

is utilizing its Contingency Reserve to mitigate an operating emergency
in accordance with its emergency Operating Plan, and

x

has depleted its Contingency Reserve to a level below its Most Severe
Single Contingency

or,
1.3.2 the Responsible Entity experiences:
x

multiple Contingencies where the combined MW loss exceeds its
Most Severe Single Contingency and that are defined as a single
Balancing Contingency Event, or

Posting #7 of Standard BAL-002-2: September 2015

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BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

x

multiple Balancing Contingency Events within the sum of the time
periods defined by the Contingency Event Recovery Period and
Contingency Reserve Restoration Period whose combined magnitude
exceeds the Responsible Entity's Most Severe Single Contingency.

M1. Each Responsible Entity shall have, and provide upon request, as evidence, a CR Form
1 with date and time of occurrence to show compliance with Requirement R1. If
Requirement R1 part 1.3 applies, then dated documentation that demonstrates
compliance with Requirement R1 part 1.3 must also be provided.
Rationale for Requirement R2: R2 establishes the need to actively plan in the near term
(e.g., day-ahead) for expected Reportable Balancing Contingency Events. This
requirement is similar to the current standard which requires an entity to have available a
level of contingency reserves equal to or greater than its Most Severe Single Contingency.
R2.

Each Responsible Entity shall develop, review and maintain annually, and implement
an Operating Process as part of its Operating Plan to determine its Most Severe
Single Contingency and make preparations to have Contingency Reserve equal to, or
greater than the Responsible Entity’s Most Severe Single Contingency available for
maintaining system reliability. [Violation Risk Factor: Medium] [Time Horizon:
Operations Planning]

M2. Each Responsible Entity will have the following documentation to show compliance
with Requirement R2:
x

a dated Operating Process;

x

evidence to indicate that the Operating Process has been reviewed and
maintained annually; and,

x

evidence such as Operating Plans or other operator documentation that
demonstrate that the entity determines its Most Severe Single Contingency
and that Contingency Reserves equal to or greater than its Most Severe Single
Contingency are included in this process.

Posting #7 of Standard BAL-002-2: September 2015

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BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

Rationale for Requirement R3: This requirement is similar to the existing requirement
that an entity that has experienced an event shall restore its Contingency Reserves within
105 minutes of the event. Note that if an entity is experiencing an EEA it may need to
depend on potential availability (or make ready for potential curtailment) of its firm loads
to restore Contingency Reserve. This is the reason for the changes to the definition of
Contingency Reserve in the posting.
R3.

Each Responsible Entity, following a Reportable Balancing Contingency Event, shall
restore its Contingency Reserve to at least its Most Severe Single Contingency,
before the end of the Contingency Reserve Restoration Period, but any Balancing
Contingency Event that occurs before the end of a Contingency Reserve Restoration
Period resets the beginning of the Contingency Event Recovery Period. [Violation
Risk Factor: Medium] [Time Horizon: Real-time Operations]

M3. Each Responsible Entity will have documentation demonstrating its Contingency
Reserve was restored within the Contingency Reserve Restoration Period, such as
historical data, computer logs or operator logs.
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 Responsible Entity shall retain data or evidence to show compliance for
the current year, plus three previous calendar years, unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer
period of time as part of an investigation.
If a Responsible Entity is found noncompliant, it shall keep information related
to the noncompliance until found compliant, or for the time period specified
above, whichever is longer.

Posting #7 of Standard BAL-002-2: September 2015

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BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

The Compliance Enforcement Authority shall keep the last audit records and
all subsequent requested and submitted records.
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
The Responsible Entity may use Contingency Reserve for any Balancing
Contingency Event and as required for any other applicable standards.

Posting #7 of Standard BAL-002-2: September 2015

Page 11 of 16

Real-time
Operations

Operations
Planning

R1.

R2.

Lower VSL

Medium The Responsible Entity
developed and
implemented an
Operating Process to
determine its Most
Severe Single
Contingency and to
have Contingency
Reserve equal to, or

The Responsible Entity
failed to use CR Form 1
to document a
Reportable Balancing
Contingency Event.

OR

Medium The Responsible Entity
achieved less than
100% but at least 90%
of required recovery
from a Reportable
Balancing Contingency
Event during the
Contingency Event
Recovery Period

VRF

Draft #7 of Standard BAL-002-2: September 2015

Time
Horizon

R#

Table of Compliance Elements

N/A

The Responsible Entity
achieved less than
90% but at least 80%
of required recovery
from a Reportable
Balancing Contingency
Event during the
Contingency Event
Recovery Period.

Moderate VSL

The Responsible Entity
developed an
Operating Process to
determine its Most
Severe Single
Contingency and to
have Contingency
Reserve equal to, or
greater than the

The Responsible Entity
achieved less than
80% but at least 70%
of required recovery
from a Reportable
Balancing Contingency
Event during the
Contingency Event
Recovery Period.

High VSL

Violation Severity Levels

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event

Page 12 of 16

The Responsible Entity
failed to develop an
Operating Process to
determine its Most
Severe Single
Contingency and to
have Contingency
Reserve equal to, or
greater than the

The Responsible Entity
achieved less than
70% of required
recovery from a
Reportable Balancing
Contingency Event
during the
Contingency Event
Recovery Period.

Severe VSL

Real-time
Operations

Medium The Responsible Entity
restored less than
100% but at least 90%
of required
Contingency Reserve
following a Reportable
Balancing Contingency
Event during the
Contingency Event
Restoration Period.

The Responsible Entity
restored less than 90%
but at least 80% of
required Contingency
Reserve following a
Reportable Balancing
Contingency Event
during the
Contingency Event
Restoration Period.

The Responsible Entity
restored less than 80%
but at least 70% of
required Contingency
Reserve following a
Reportable Balancing
Contingency Event
during the
Contingency Event
Restoration Period.

Responsible Entity’s
Most Severe Single
Contingency but failed
to implement the
Operating Process.

Draft #7 of Standard BAL-002-2: September 2015

CR Form 1

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event Background Document

F. Associated Documents

None.

E. Interpretations

None.

D. Regional Variances

R3

greater than the
Responsible Entity’s
Most Severe Single
Contingency but failed
to maintain annually
the Operating Process.

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event

Page 13 of 16

The Responsible Entity
restored less than 70%
of required
Contingency Reserve
following a Reportable
Balancing Contingency
Event during the
Contingency Event
Restoration Period.

Responsible Entity’s
Most Severe Single
Contingency..

August 8, 2005

February 14,
2006

September 9,
2010

January 10, 2011

April 1, 2012

November 2015

0

0

1

1

1

2

NERC Board Adoption

Effective Date of BAL-002-1

Commission approved BAL-002-1

Filed petition for revisions to BAL-002 Version 1 with
the Commission

Revised graph on page 3, “10 min.” to “Recovery
time.” Removed fourth bullet.

Removed “Proposed” from Effective Date

Effective Date

Action

Complete revision

Revision

Errata

Errata

New

Change Tracking

Draft #7 of Standard BAL-002-2: September 2015

Page 14 of 16

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.

April 1, 2005

Date

0

Version

Version History

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event

Supplemental Material
[Application Guidelines, Guidelines and Technical Basis, Training Material,
Reference Material and/or other Supplemental Material]

Draft #7 of Standard BAL-002-2: September 2015

Page 15 of 16

Supplemental Material
Rationale
Upon Board approval, the text from the rationale boxes will be moved to this section.

Draft #7 of Standard BAL-002-2: September 2015

Page 16 of 16

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

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
(Describe the type of action associated with this posting, such as 30-day informal comment
period, 45-day formal comment period with parallel ballot, 45-day formal comment period with
parallel additional ballot, final ballot.)

Completed Actions

Date

The SAR for Project 2007-18, Reliability Based Controls, was posted
for a 30-day formal industry comment period.

May 15, 2007

The SAR for Project 2007-05, Balancing Authority Controls, was
posted for a 30-day formal industry comment period.

July 3, 2007

A revised SAR for Project 2007-05, Reliability Based Controls, was
posted for a second 30-day formal industry comment period.

September 10, 2007

The Standards Committee approved Project 2007-18, Reliability
Based Controls, to be moved to standard drafting.

December 11, 2007

The SAR for Project 2007-05, Balancing Authority Controls, was
posted for a 30-day formal industry comment period.

July 3, 2007

The Standards Committee approved Project 2007-05, Balancing
Authority Controls, to be moved to standard drafting.

January 18, 2008

The Standards Committee approved the merger of Project 2007-05,
Balancing Authority Controls, and Project 2007-18, Reliability-based
Control, as Project 2010-14, Balancing Authority Reliability-based
Controls.

July 28, 2010

The NERC Standards Committee approved breaking Project 2010-14,
Balancing Authority Reliability-based Controls, into two phases and
moving Phase 1 (Project 2010-14.1, Balancing Authority Reliabilitybased Controls – Reserves) into formal standards development.

July 13, 2011

The draft standard was posted for 30-day formal industry comment
period.

June 4, 2012

The second draft standard was posted for 45-day formal industry
comment period and initial ballot.

March 12, 2013

Posting #7 of Standard BAL-002-2: September 2015

Page 1 of 17

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

The third draft standard was posted for 45-day formal industry
comment period and additional ballot.

August 2, 2013

The fourth draft standard was posted for 45-day formal industry
comment period and additional ballot.

October 28, 2013

The fifth draft standard was posted for a 45 day formal industry
comment period and additional ballot.

August 20, 2014

The sixth draft standard was posted for a 45-day formal industry
comment period and additional ballot.

January 29, 2015

The seventh draft standard was posted for a 45-day formal industry
comment period and additional ballot.

July 7, 2015

Anticipated Actions

Date

45-day formal comment period with parallel additional ballot

June/July 2015

Final ballot

July September
2015

NERC Board adoption

August November
2015

Posting #7 of Standard BAL-002-2: September 2015

Page 2 of 17

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

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:
Balancing Contingency Event: Any single event described in Subsections (A), (B), or (C) below,
or any series of such otherwise single events, with each separated from the next by one minute
or less.
A. Sudden loss of generation:
a. Due to
i. unit tripping,
ii. loss of generator Facility resulting in isolation of the generator from the
Bulk Electric System or from the responsible entity’s System, or
iii. sudden unplanned outage of transmission Facility;
b. And, that causes an unexpected change to the responsible entity’s ACE;
B. Sudden loss of an import, due to unplanned outage of transmission equipment that
causes an unexpected imbalance between generation and Demand on the
Interconnection.
C. Sudden restoration of a Demand that was used as a resource that causes an unexpected
change to the responsible entity’s ACE.
Most Severe Single Contingency (MSSC): The Balancing Contingency Event, due to a single
contingency as identified and maintained in theusing system models maintained within the
Reserve Sharing Group (RSG), or a Balancing Authority’s area that is not part of a Reserve
Sharing Group, that would result in the greatest loss (measured in MW) of resource output
used by the RSG or a Balancing Authority that is not participating as a member of a RSG at the
time of the event to meet Firm Demand and export obligation (excluding export obligation for
which Contingency Reserve obligations are being met by the Sink Balancing Authority).
Reportable Balancing Contingency Event: Any Balancing Contingency Event occurring within a
one-minute interval of an initial sudden decline in ACE based on EMS scan rate data that results
in a loss of MW output less than or equal to the Most Severe Single Contingency, and greater
than or equal to the lesser amount of: (i) 80% of the Most Severe Single Contingency, or (ii) the
amount listed below for the applicable Interconnection. Prior to any given calendar quarter,
the 80% threshold may be reduced by the responsible entity upon written notification to the
Regional Entity.
x

Eastern Interconnection - 900 MW

x

Western Interconnection – 500 MW

Posting #7 of Standard BAL-002-2: September 2015

Page 3 of 17

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

x

ERCOT – 800 MW

x

Quebec – 500 MW

Contingency Event Recovery Period: A period that begins at the time that the resource output
begins to decline within the first one-minute interval of a Reportable Balancing Contingency
Event, and extends for fifteen minutes thereafter.
Contingency Reserve Restoration Period: A period not exceeding 90 minutes following the end
of the Contingency Event Recovery Period.
Pre-Reporting Contingency Event ACE Value: The average value of Reporting ACE, or Reserve
Sharing Group Reporting ACE when applicable, in the 16-second interval immediately prior to
the start of the Contingency Event Recovery Period based on EMS scan rate data.
Reserve Sharing Group Reporting ACE: At any given time of measurement for the applicable
Reserve Sharing Group (RSG), the algebraic sum of the ACEs (or equivalent as calculated at such
time of measurement) of the Balancing Authorities participating in the RSG at the time of
measurement.
Rationale for Contingency Reserve Definition: Originally a waiver of the R3
Contingency Reserve Restoration requirement was proposed in the event of an
Energy Emergency Alert (EEA). This was predicated on a definition of Contingency
Reserve that did not include readiness to reduce Firm Demand during the
Contingency Reserve Restoration Period during an EEA and on concern that the
attempt to restore Contingency Reserve during an EEA could well result in actual
curtailment of Firm Demand in order to free up generation not to be used but merely
to be counted as restored Contingency Reserve when no other Balancing Contingency
Event arose. As an alternative to waiving R3, and to remedy the concern, readiness to
reduce Firm Demand during the Contingency Reserve Restoration Period during an
EEA was proposed for inclusion in the definition of Contingency Reserve as it would
make Firm Demand merely ready to be curtailed in case another Contingency arose
during an EEA.
Readiness to reduce Firm Demand here is a way of providing Contingency Reserves
exclusively when the Responsible Entity is in a Contingency Reserve Restoration
Period during an emergency. Readiness means the Responsible Entity is prepared to
reduce Firm Demand to mitigate events which may increase demand or reduce supply
causing unacceptable risk. The Responsible Entity should have processes and

Posting #7 of Standard BAL-002-2: September 2015

Page 4 of 17

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

procedures for direct control over the Firm Demand in place for it to be considered
Contingency Reserves prior to the event.
Contingency Reserve: The provision of capacity that may be deployed by the Balancing
Authority to respond to a Balancing Contingency Event and other contingency requirements
(such as Energy Emergency Alerts as specified in the associated EOP standard). A Balancing
Authority may include in its restoration of Contingency Reserve readiness to reduce Firm
Demand and include it if, and only if, the Balancing Authority:
x

is experiencing a Reliability Coordinator declared Energy Emergency Alert level, and

x

is utilizing its Contingency Reserve to mitigate an operating emergency in
accordance with its emergency Operating Plan.

Posting #7 of Standard BAL-002-2: September 2015

Page 5 of 17

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

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: Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event

2.
3.

Number: BAL-002-2
Purpose: To ensure the Balancing Authority or Reserve Sharing Group balances
resources and demand and returns the Balancing Authority's or Reserve Sharing
Group's Area Control Error to defined values (subject to applicable limits) following a
Reportable Balancing Contingency Event.

4.

Applicability:
4.1. Responsible Entity
4.1.1. Balancing Authority
4.1.1.1.
A Balancing Authority that is a member of a Reserve
Sharing Group is the Responsible Entity only in periods during
which the Balancing Authority is not in active status under the
applicable agreement or governing rules for the Reserve Sharing
Group.
4.1.2. Reserve Sharing Group

5.

Effective Date: See the Implementation Plan for BAL-002-2.

6.

Background:
Reliably balancing an Interconnection requires frequency management and all of its
aspects. Inputs to frequency management include Tie-Line Bias Control, Area Control
Error (ACE), and the various Requirements in NERC Resource and Demand Balancing
Standards, specifically BAL-001-2 Real Power Balancing Control Performance and BAL003-1 Frequency Response and Frequency Bias Setting.

B. Requirements and Measures

Posting #7 of Standard BAL-002-2: September 2015

Page 6 of 17

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

Rationale for Requirement R1: Requirement R1 reflects the operating principles first
established by NERC Policy 1 (Generation Control and Performance). Its objective is to
assure the Responsible Entity balances resources and demand and returns its Reporting
Area Control Error (ACE) to defined values (subject to applicable limits) following a
Reportable Balancing Contingency Event. It requires the Responsible Entity to recover
from events that would be less than or equal to the Responsible Entity’s MSSC. It
establishes the amount of Contingency Reserve and recovery and restoration timeframes
the Responsible Entity must demonstrate in a compliance evaluation. It is intended to
eliminate the ambiguities and questions associated with the existing standard. In
addition, it allows Responsible Entities to have a clear way to demonstrate compliance
and support the Interconnection to the full extent of its MSSC.
Requirement R1 does not apply when an entity experiences a Balancing Contingency
Event that exceeds its MSSC (which includes multiple Balancing Contingency Events as
described in R1 part 1.3.2 below) because a fundamental goal of the SDT is to assure the
Responsible Entity has enough flexibility to maintain service to Demand while managing
reliability. The SDT’s intent is to eliminate any potential overlap or conflict with any other
NERC Reliability Standard to eliminate duplicative reporting, and other issues.
Commenters suggested a Quarterly Compliance similar to the current reports sent to
NERC. The drafting team attempted to draft measurement language and VSL’s for
quarterly monitoring of compliance to R1. But the drafting team found that the VSL levels
developed were likely to place smaller BA’s and RSGs in a severe violation regardless of
the size of the failure. Therefore, the drafting team has not adopted a quarterly
compliance calculation. Also, the proposed requirement and compliance process meets
the directive in Paragraph 354 of Order 693.
Finally, commenters have suggested that the language in R1 part 1.3 be changed to
specifically state under which EEA level the exclusion applies. The drafting team disagrees
with this proposal. NERC is in the process of changing the EEA levels and what is expected
in each level. The current EEA levels suggest that when an entity is experiencing an EEA
Level 2 or 3 it is short of Contingency Reserves as normally defined to exclude readiness
to curtail a specific amount of Firm Demand. Under the proposed EEA process, this would
only be during an EEA Level 3. In order to reduce the need for consequent modifications
of the BAL-002 standard, the drafting team has developed the proposed language in
Requirement 1 Part 1.3.1 such that it addresses both current and future EEA process. In
addition, the drafting team has added some clarifying language to 1.3.1 since comments
were presented in previous postings expressing a concern only a Balancing Authority may
request declaration of an EEA and a RSG cannot request an EEA. The standard drafting
team’s intent has always been if a BA is experiencing an EEA event under which its
contingency reserve has been activated, the RSG in which it resides would also be
considered to be exempt from R1 compliance.

Posting #7 of Standard BAL-002-2: September 2015

Page 7 of 17

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

R1.

The Responsible Entity experiencing a Reportable Balancing Contingency Event shall:
[Violation Risk Factor: Medium] [Time Horizon: Real-time Operations]
1.1. within the Contingency Event Recovery Period, demonstrate recovery by
returning its Reporting ACE to at least the recovery value of:
x

zero (if its Pre-Reporting Contingency Event ACE Value was positive or equal
to zero); however, any Balancing Contingency Event that occurs during the
Contingency Event Recovery Period shall reduce the required recovery: (i)
beginning at the time of, and (ii) by the magnitude of, such individual
Balancing Contingency Event,

or,
x

its Pre-Reporting Contingency Event ACE Value (if its Pre-Reporting
Contingency Event ACE Value was negative); however, any Balancing
Contingency Event that occurs during the Contingency Event Recovery Period
shall reduce the required recovery: (i) beginning at the time of, and (ii) by the
magnitude of, such individual Balancing Contingency Event.

1.2. document all Reportable Balancing Contingency Events using CR Form 1.
1.3. deploy Contingency Reserve, within system constraints, to respond to all
Reportable Balancing Contingency Events, however, it is not subject to
compliance with Requirement R1 part 1.1 if:
1.3.1 the Responsible Entity is:
x

is a Balancing Authority experiencing a Reliability Coordinator declared
Energy Emergency Alert Level or is a Reserve Sharing Group whose
member, or members, are experiencing a Reliability Coordinator
declared Energy Emergency Alert level, and

x

is utilizing its Contingency Reserve to mitigate an operating emergency
in accordance with its emergency Operating Plan, and

x

the Responsible Entity has depleted its Contingency Reserve to a level
below its Most Severe Single Contingency

or,
1.3.2 the Responsible Entity experiences:
x

multiple Contingencies where the combined MW loss exceeds its
Most Severe Single Contingency and that are defined as a single
Balancing Contingency Event, or

Posting #7 of Standard BAL-002-2: September 2015

Page 8 of 17

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

x

multiple Balancing Contingency Events within the sum of the time
periods defined by the Contingency Event Recovery Period and
Contingency Reserve Restoration Period whose combined magnitude
exceeds the Responsible Entity's Most Severe Single Contingency.

M1. Each Responsible Entity shall have, and provide upon request, as evidence, a CR Form
1 with date and time of occurrence to show compliance with Requirement R1. If
Requirement R1 part 1.3 applies, then dated documentation that demonstrates
compliance with Requirement R1 part 1.3 must also be provided.
Rationale for Requirement R2: R2 establishes the need to actively plan in the near term
(e.g., day-ahead) for expected Reportable Balancing Contingency Events. This
requirement is similar to the current standard which requires an entity to have available a
level of contingency reserves equal to or greater than its Most Severe Single Contingency.
R2.

Each Responsible Entity shall develop, review and maintain annually, and implement
an Operating Process as part of its Operating Plan to determine its Most Severe
Single Contingency and make preparations to have Contingency Reserve equal to, or
greater than the Responsible Entity’s Most Severe Single Contingency available for
maintaining system reliability. [Violation Risk Factor: Medium] [Time Horizon:
Operations Planning]

M2. Each Responsible Entity will have the following documentation to show compliance
with Requirement R2:
x

a dated Operating Process;

x

evidence to indicate that the Operating Process has been reviewed and
maintained annually; and,

x

evidence such as Operating Plans or other operator documentation that
demonstrate that the entity determines its Most Severe Single Contingency
and that Contingency Reserves equal to or greater than its Most Severe Single
Contingency are included in this process.

Posting #7 of Standard BAL-002-2: September 2015

Page 9 of 17

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

Rationale for Requirement R3: This requirement is similar to the existing requirement
that an entity that has experienced an event shall restore its Contingency Reserves within
105 minutes of the event. Note that if an entity is experiencing an EEA it may need to
depend on potential availability (or make ready for potential curtailment) of its firm loads
to restore Contingency Reserve. This is the reason for the changes to the definition of
Contingency Reserve in the posting.
R3.

Each Responsible Entity, following a Reportable Balancing Contingency Event, shall
restore its Contingency Reserve to at least its Most Severe Single Contingency,
before the end of the Contingency Reserve Restoration Period, but any Balancing
Contingency Event that occurs before the end of a Contingency Reserve Restoration
pPeriod resets the beginning of the Contingency Event Recovery Period. [Violation
Risk Factor: Medium] [Time Horizon: Real-time Operations]

M3. Each Responsible Entity will have documentation demonstrating its Contingency
Reserve was restored within the Contingency Reserve Restoration Period, such as
historical data, computer logs or operator logs.
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 Responsible Entity shall retain data or evidence to show compliance for
the current year, plus three previous calendar years, unless directed by its
Compliance Enforcement Authority to retain specific evidence for a longer
period of time as part of an investigation.
If a Responsible Entity is found noncompliant, it shall keep information related
to the noncompliance until found compliant, or for the time period specified
above, whichever is longer.

Posting #7 of Standard BAL-002-2: September 2015

Page 10 of 17

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing
Contingency Event

The Compliance Enforcement Authority shall keep the last audit records and
all subsequent requested and submitted records.
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
The Responsible Entity may use Contingency Reserve for any Balancing
Contingency Event and as required for any other applicable standards.

Posting #7 of Standard BAL-002-2: September 2015

Page 11 of 17

Real-time
Operations

Operations
Planning

R1.

R2.

Lower VSL

Medium The Responsible Entity
developed and
implemented an
Operating Process to
determine its Most
Severe Single
Contingency and to
have Contingency
Reserve equal to, or

The Responsible Entity
failed to use CR Form 1
to document a
Reportable Balancing
Contingency Event.

OR

Medium The Responsible Entity
achieved less than
100% but at least 90%
of required recovery
from a Reportable
Balancing Contingency
Event during the
Contingency Event
Recovery Period

VRF

Draft #7 of Standard BAL-002-2: September 2015

Time
Horizon

R#

Table of Compliance Elements

N/A

The Responsible Entity
achieved less than
90% but at least 80%
of required recovery
from a Reportable
Balancing Contingency
Event during the
Contingency Event
Recovery Period.

Moderate VSL

The Responsible Entity
developed an
Operating Process to
determine its Most
Severe Single
Contingency and to
have Contingency
Reserve equal to, or
greater than the

The Responsible Entity
achieved less than
80% but at least 70%
of required recovery
from a Reportable
Balancing Contingency
Event during the
Contingency Event
Recovery Period.

High VSL

Violation Severity Levels

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event

Page 12 of 17

The Responsible Entity
failed to develop an
Operating Process to
determine its Most
Severe Single
Contingency and to
have Contingency
Reserve equal to, or
greater than the

The Responsible Entity
achieved less than
70% of required
recovery from a
Reportable Balancing
Contingency Event
during the
Contingency Event
Recovery Period.

Severe VSL

Real-time
Operations

Medium The Responsible Entity
restored less than
100% but at least 90%
of required
Contingency Reserve
following a Reportable
Balancing Contingency
Event during the
Contingency Event
Restoration Period.

The Responsible Entity
restored less than 90%
but at least 80% of
required Contingency
Reserve following a
Reportable Balancing
Contingency Event
during the
Contingency Event
Restoration Period.

The Responsible Entity
restored less than 80%
but at least 70% of
required Contingency
Reserve following a
Reportable Balancing
Contingency Event
during the
Contingency Event
Restoration Period.

Responsible Entity’s
Most Severe Single
Contingency but failed
to implement the
Operating Process.

Draft #7 of Standard BAL-002-2: September 2015

Version History

CR Form 1

BAL-002-2 Contingency Reserve for Recovery from a Balancing Contingency Event Background Document

F. Associated Documents

None.

E. Interpretations

None.

D. Regional Variances

R3

greater than the
Responsible Entity’s
Most Severe Single
Contingency but failed
to maintain annually
the Operating Process.

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event

Page 13 of 17

The Responsible Entity
restored less than 70%
of required
Contingency Reserve
following a Reportable
Balancing Contingency
Event during the
Contingency Event
Restoration Period.

Responsible Entity’s
Most Severe Single
Contingency..

August 8, 2005

February 14,
2006

September 9,
2010

January 10, 2011

April 1, 2012

November 2015

0

0

1

1

1

2

Action

NERC BOT Board Adoption

Effective Date of BAL-002-1

Commission approved BAL-002-1

Filed petition for revisions to BAL-002 Version 1 with
the Commission

Revised graph on page 3, “10 min.” to “Recovery
time.” Removed fourth bullet.

Removed “Proposed” from Effective Date

Effective Date

Draft #7 of Standard BAL-002-2: September 2015

Standards Attachments

April 1, 2005

Date

0

Version

Complete revision

Revision

Errata

Errata

New

Change Tracking

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event

Page 14 of 17

Draft #7 of Standard BAL-002-2: September 2015

Page 15 of 17

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.

BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event

Supplemental Material
[Application Guidelines, Guidelines and Technical Basis, Training Material,
Reference Material and/or other Supplemental Material]

Draft #7 of Standard BAL-002-2: September 2015

Page 16 of 17

Supplemental Material
Rationale
Upon Board approval, the text from the rationale boxes will be moved to this section.

Draft #7 of Standard BAL-002-2: September 2015

Page 17 of 17

Implementation Plan

Project 2010-14.1 Balancing Authority Reliability-based
Controls – Reserves
BAL-002-2

Approvals Required
BAL-002-2 – Disturbance Control Standard - Contingency Reserve for Recovery from a Balancing
Contingency Event
Prerequisite Approvals
None
Revisions to Glossary Terms
The following definitions shall become effective when BAL-002-2 becomes effective:
Balancing Contingency Event: Any single event described in Subsections (A), (B), or (C) below, or
any series of such otherwise single events, with each separated from the next by one minute or
less.
A. Sudden loss of generation:
a. Due to
i. unit tripping, or
ii. loss of generator Facility resulting in isolation of the generator from the Bulk
Electric System or from the responsible entity’s System, or
iii. sudden unplanned outage of transmission Facility;
b. And, that causes an unexpected change to the responsible entity’s ACE;
B. Sudden loss of an Import, due to forced outage of transmission equipment that causes an
unexpected imbalance between generation and Demand on the Interconnection.
C. Sudden restoration of a Demand that was used as a resource that causes an unexpected
change to the responsible entity’s ACE.
Most Severe Single Contingency (MSSC): The Balancing Contingency Event, due to a single
contingency identified using system models maintained within the Reserve Sharing Group (RSG) or
a Balancing Authority’s area that is not part of a Reserve Sharing Group, that would result in the
greatest loss (measured in MW) of resource output used by the RSG or a Balancing Authority that is
not participating as a member of a RSG at the time of the event to meet Firm Demand and export

obligation (excluding export obligation for which Contingency Reserve obligations are being met by
the Sink Balancing Authority).
Reportable Balancing Contingency Event: Any Balancing Contingency Event occurring within a
one-minute interval of an initial sudden decline in ACE based on EMS scan rate data that results in a
loss of MW output less than or equal to the Most Severe Single Contingency, and greater than or
equal to the lesser amount of: (i) 80% of the Most Severe Single Contingency, or (ii) the amount
listed below for the applicable Interconnection. Prior to any given calendar quarter, the 80%
threshold may be reduced by the responsible entity upon written notification to the Regional
Entity.
x

Eastern Interconnection – 900 MW

x

Western Interconnection – 500 MW

x

ERCOT – 800 MW

x

Quebec – 500 MW

Contingency Event Recovery Period: A period that begins at the time that the resource output
begins to decline within the first one-minute interval of a Reportable Balancing Contingency Event,
and extends for fifteen minutes thereafter.
Contingency Reserve Restoration Period: A period not exceeding 90 minutes following the end of
the Contingency Event Recovery Period.
Pre-Reporting Contingency Event ACE Value: The average value of Reporting ACE, or Reserve
Sharing Group Reporting ACE when applicable, in the 16-second interval immediately prior to the
start of the Contingency Event Recovery Period based on EMS scan rate data.
Reserve Sharing Group Reporting ACE: At any given time of measurement for the applicable
Reserve Sharing Group (RSG), the algebraic sum of the ACEs (or equivalent as calculated at such
time of measurement) of the Balancing Authorities participating in the RSG at the time of
measurement.
Contingency Reserve: The provision of capacity that may be deployed by the Balancing Authority to
respond to a Balancing Contingency Event and other contingency requirements (such as Energy
Emergency Alerts as specified in the associated EOP standard). A Balancing Authority may include
in its restoration of Contingency Reserve readiness to reduce Firm Demand and include it if, and
only if, the Balancing Authority:
x

is experiencing a Reliability Coordinator declared Energy Emergency Alert level, and

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x

is utilizing its Contingency Reserve to mitigate an operating emergency in accordance with
its emergency Operating Plan.

Applicable Entities
Balancing Authority1
Reserve Sharing Group
Applicable Facilities
N/A
Conforming Changes to Other Standards
None
Effective Dates
BAL-002-2 shall become effective the first day of the first calendar quarter that is six months after the
date that this standard is approved by applicable 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 six months after the date the
standard is adopted by the NERC Board of Trustees, or as otherwise provided for in that jurisdiction.
Justification
The six-month period for implementation of BAL-002-2 will provide ample time for Balancing
Authorities to make necessary modifications to existing software programs to ensure compliance.
Retirements

1

A Balancing Authority that is a member of a Reserve Sharing Group is the Responsible Entity only in periods during which
the Balancing Authority is not in active status under the applicable agreement or governing rules for the Reserve Sharing
Group. See Section A.4.1.1.1, BAL-002-2.

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Reliability Standard BAL-002-1, Disturbance Control Performance shall be retired immediately prior to
the effective date of BAL-002-2 in the particular jurisdiction in which the new standard is becoming
effective.
The existing definition of Contingency Reserve should be retired immediately prior to the effective
date of BAL-002-2, in the particular jurisdiction in which the new standard is becoming effective.

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Implementation Plan

Project 2010-14.1 Balancing Authority Reliability-based
Controls – Reserves
BAL-002-2

Approvals Required
BAL-002-2 – Disturbance Control Standard - Contingency Reserve for Recovery from a Balancing
Contingency Event
Prerequisite Approvals
None
Revisions to Glossary Terms
The following definitions shall become effective when BAL-002-2 becomes effective:
Balancing Contingency Event: Any single event described in Subsections (A), (B), or (C) below, or
any series of such otherwise single events, with each separated from the next by one minute or
less.
A. Sudden loss of generation:
a. Due to
i. unit tripping, or
ii. loss of generator Facility resulting in isolation of the generator from the Bulk
Electric System or from the responsible entity’s System, or
iii. sudden unplanned outage of transmission Facility;
b. And, that causes an unexpected change to the responsible entity’s ACE;
B. Sudden loss of an Import, due to forced outage of transmission equipment that causes an
unexpected imbalance between generation and Demand on the Interconnection.
C. Sudden restoration of a Demand that was used as a resource that causes an unexpected
change to the responsible entity’s ACE.
Most Severe Single Contingency (MSSC): The Balancing Contingency Event, due to a single
contingency as identified and maintained in theusing system models maintained within the Reserve
Sharing Group (RSG) or a Balancing Authority’s area that is not part of a Res area that is not part of
a Reserve Sharing Group, that would result in the greatest loss (measured in MW) of resource
output used by the RSG or a Balancing Authority that is not participating as a member of a RSG at

the time of the event to meet Firm Demand and export obligation (excluding export obligation for
which Contingency Reserve obligations are being met by the Sink Balancing Authority).
Reportable Balancing Contingency Event: Any Balancing Contingency Event occurring within a
one-minute interval of an initial sudden decline in ACE based on EMS scan rate data that results in a
loss of MW output less than or equal to the Most Severe Single Contingency, and greater than or
equal to the lesser amount of: (i) 80% of the Most Severe Single Contingency, or (ii) the amount
listed below for the applicable Interconnection. Prior to any given calendar quarter, the 80%
threshold may be reduced by the responsible entity upon written notification to the Regional
Entity.
x

Eastern Interconnection – 900 MW

x

Western Interconnection – 500 MW

x

ERCOT – 800 MW

x

Quebec – 500 MW

Contingency Event Recovery Period: A period that begins at the time that the resource output
begins to decline within the first one-minute interval of a Reportable Balancing Contingency Event,
and extends for fifteen minutes thereafter.
Contingency Reserve Restoration Period: A period not exceeding 90 minutes following the end of
the Contingency Event Recovery Period.
Pre-Reporting Contingency Event ACE Value: The average value of Reporting ACE, or Reserve
Sharing Group Reporting ACE when applicable, in the 16-second interval immediately prior to the
start of the Contingency Event Recovery Period based on EMS scan rate data.
Reserve Sharing Group Reporting ACE: At any given time of measurement for the applicable
Reserve Sharing Group (RSG), the algebraic sum of the ACEs (or equivalent as calculated at such
time of measurement) of the Balancing Authorities participating in the RSG at the time of
measurement.
Contingency Reserve: The provision of capacity that may be deployed by the Balancing Authority to
respond to a Balancing Contingency Event and other contingency requirements (such as Energy
Emergency Alerts as specified in the associated EOP standard). A Balancing Authority may include
in its restoration of Contingency Reserve readiness to reduce Firm Demand and include it if, and
only if, the Balancing Authority:
x

is experiencing a Reliability Coordinator declared Energy Emergency Alert level, and

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x

is utilizing its Contingency Reserve to mitigate an operating emergency in accordance with
its emergency Operating Plan.

The existing definition of Contingency Reserve should be retired at midnight of the day immediately
prior to the effective date of BAL-002-2, in the jurisdiction in which the new standard is becoming
effective.
Applicable Entities
Balancing Authority1
Reserve Sharing Group
Applicable Facilities
N/A
Conforming Changes to Other Standards
None
Effective Dates
BAL-002-2 shall become effective the first day of the first calendar quarter that is six months after the
date that this standard is approved by applicable 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 six months after the date the
standard is adopted by the NERC Board of Trustees, or as otherwise provided for in that jurisdiction.
Justification
The six-month period for implementation of BAL-002-2 will provide ample time for Balancing
Authorities to make necessary modifications to existing software programs to ensure compliance.
Retirements

1

A Balancing Authority that is a member of a Reserve Sharing Group is the Responsible Entity only in periods during which
the Balancing Authority is not in active status under the applicable agreement or governing rules for the Reserve Sharing
Group. See Section A.4.1.1.1, BAL-002-2.

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Reliability Standard BAL-002-0, Disturbance Control Performance, and BAL-002-1, Disturbance Control
Performance shall be retired at midnight of the day immediately prior to the Eeffective Ddate of BAL002-2 in the particular jurisdiction in which the new standard is becoming effective.
The existing definition of Contingency Reserve should be retired immediately prior to the effective
date of BAL-002-2, in the particular jurisdiction in which the new standard is becoming effective.

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BAL-002-2
Background Document
September 2015

BALͲ002Ͳ2ͲBackgroundDocument
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Table of Contents
Introduction .................................................................................................................................... 3
RationalebyRequirement .............................................................................................................. 7
Requirement1 ............................................................................................................................ 7
Requirement2 .......................................................................................................................... 14
Requirement3 .......................................................................................................................... 15


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Introduction
TherevisiontoNERCPolicyStandardsin1996createdaDisturbanceControlStandard(DCS).It
replacedB1[AreaControlError(ACE)mustreturntozerowithin10minutesfollowinga
disturbance]andB2(ACEmuststarttoreturntozeroin1minutefollowingadisturbance)with
astandardthatstates:ACEmustreturntoeitherzeroorapreͲdisturbancevalueofACEwithin
15minutesfollowingareportabledisturbance.BalancingAuthoritieswererequiredtoreport
alldisturbancesequaltoorgreaterthan80%oftheBalancingAuthority’sMostSevereSingle
Contingency(MSSC).

BALͲ002wascreatedtoreplaceportionsofPolicy1.Itmeasurestheabilityofanapplicable
entitytorecoverfromareportableeventwiththedeploymentofreserve.Thereliable
operationoftheinterconnectedpowersystemrequiresthatadequatecapacityandenergybe
availabletomaintainscheduledfrequencyandavoidlossoffirmloadfollowinglossof
transmissionorgenerationcontingencies.Thiscapacity(ContingencyReserve)isnecessaryto
replacecapacityandenergylostduetoforcedoutagesofgenerationortransmission
equipment.ThedesignofBALͲ002andPolicy1waspredicatedontheInterconnection’s
operatingundernormalconditions,andtherequirementsofBALͲ002assuredrecoveryfrom
singlecontingency(NͲ1)events.

ThisdocumentprovidesbackgroundonthedevelopmentandimplementationofBALͲ002Ͳ2Ͳ
ContingencyReserveforRecoveryfromaBalancingContingencyEvent.Thisdocumentexplains
therationaleandconsiderationsfortherequirementsandtheirassociatedcompliance
information.BALͲ002Ͳ2wasdevelopedtofulfilltheNERCBalancingAuthorityControls(Project
2007Ͳ05)StandardAuthorizationRequest(SAR),whichincludestheincorporationoftheFERC
Order693directives.TheoriginalSAR,approvedbytheindustry,presumesthereispresently
sufficientContingencyReserveinalltheNorthAmericanInterconnections.Theunderlyinggoal
oftheSARwastoupdatethestandardtomakethemeasurementprocessmoreobjectiveand
toprovideinformationtotheBalancingAuthorityorReserveSharingGroup,suchthatthe
partieswouldbetterunderstandtheuseofContingencyReservetobalanceresourcesand
demandfollowingaReportableBalancingContingencyEvent.

Currently,theexistingBALͲ002Ͳ1standardcontainsRequirementsspecifictoaReserveSharing
Groupwhichthedraftingteambelievesarecommercialinnatureandacontractual
arrangementbetweenthereservesharinggroupparties.BALͲ002Ͳ2isintendedtomeasurethe
successfuldeploymentofcontingencyreservebyresponsibleentities.Relationshipsbetween
theentitiesshouldnotbepartoftheperformancerequirements,butleftuptoacommercial
transaction.
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DisturbanceControlPerformanceͲContingencyReserveforRecoveryFromaBalancing
ContingencyEventStandardBackgroundDocument

Clarityandspecificsareprovidedwithseveralnewdefinitions.Additionally,theBALͲ002Ͳ2
eliminatesanyquestionaboutwhoistheapplicableentityandassuresthattheapplicable
entityisheldresponsiblefortheperformancerequirement.Thedraftingteam’sgoalwasto
haveBALͲ002Ͳ2besolelyaperformancestandard.TheprimaryobjectiveofBALͲ002Ͳ2isto
ensurethattheapplicableentityispreparedtobalanceresourcesanddemandandtoreturnits
ACEtodefinedvalues(subjecttoapplicablelimits)followingaReportableBalancing
ContingencyEvent.

Asproposed,thisstandardisnotintendedtoaddresseventsgreaterthanaResponsibleEntity’s
MostSevereSingleContingency.TheselargemultiͲunitevents,althoughunlikely,dooccur.
ManyinteractionsoccurduringtheseeventsandBalancingAuthorities(BAs)andReserve
SharingGroupsmustreacttotheseevents.However,requiringarecoveryofACEwithina
specifictimeperiodismuchtoosimpleamethodologytoadequatelyaddressallofthese
interactions.ThesuiteofNERCStandardsworktogethertoensurethattheInterconnections
areoperatedinasafeandreliablemanner.Itisnotjustonestandard,ratheritisthe
combinationoftheBALͲ001Ͳ2standard(inwhichR2requiresoperationwithinanACE
bandwidthbasedoninterconnectionfrequency),TOPͲ007,andEOPͲ002,whichcollectively
addressissueswhenlargeeventsoccur.
x

TheBalancingAuthorityACELimit(BAAL)inR2ofBALͲ001Ͳ2looksatInterconnection
frequencytoprovidetheBAarangeinwhichtheBAshouldstrivetooperateaswellas
a30ͲminuteperiodtoaddressinstanceswhentheBAisoutsideofthatrange.Ifan
eventlargerthantheBA’sMSSCoccurs,theBAALwilllikelychangetoamuchtighter
controllimitbasedonthechangeininterconnectionfrequency.The30Ͳminutelimit
undertheBAALallowstheBA(anditsRC)timetoquicklyevaluatethebestcourseof
actionandthenreactinareasonablemanner.BAALalsoensurestheResponsibleEntity
balancesresourcesanddemandwheneventsoccuroflessmagnitudethanaReportable
BalancingContingency.InadditionR1ofBALͲ001Ͳ2requirestheBAtorespondto
assureControlPerformanceStandard1(CPS1)ismet.ThismayprompttheBAto
respondinsomecircumstancesinlessthan10minutes.

x

TheTOPͲ007standardaddressestransmissionlineloading.MembersoftheBALͲ002Ͳ2
draftingteamareawareofinstances(typicallyNͲ2orless)thatcouldcausetransmission
overloadsifcertainunitswerelostandreservesresponded.

x

UnderEOPͲ002,iftheBAdoesnotbelievethatitcanmeetcertainparameters,different
rulesareimplemented.

Becauseofthepotentialforsignificantunintendedconsequencesthatcouldoccurundera
requirementtoactivateallreserves,thedraftingteamrecommendstotheindustrythatthe
revisedBALͲ002Ͳ2addressonlyeventswhichareplannedfor(NͲ1)andnotanylossof
resource(s)thatwouldexceedMSSC.Therefore,thedefinitionsandRequirementsunderBALͲ
002Ͳ2excludeeventsgreaterthantheMSSC.ThisprovidesclarityofRequirements,supports
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DisturbanceControlPerformanceͲContingencyReserveforRecoveryFromaBalancing
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reliableoperationoftheBulkElectricSystemandallowsotherstandardstoaddresseventsof
greatermagnitudeandcomplexity.

WithinNERC’sStateofReliabilityReport,ALR2Ͳ5“DisturbanceControlEventsGreaterThanthe
MostSevereSingleContingency”hasbeentrackedandreportedsince2006.Fortheperiod
2006to2011therewere90disturbanceeventsthatexceededtheMSSC,withthehighestin
anygivenyearbeing24events.EvaluationofthedataillustrateseventsgreaterthanMSSC
occurveryinfrequently,andthedraftingteambelievestheirexclusionwillnothaveany
adverseimpactonreliability.

ThemetricreportsthenumberofDCSeventsgreaterthanMSSC,regardlessofthesizeofa
BalancingAuthorityorRSGandofthenumberofreportingentitieswithinaRegionalEntity.A
smallBalancingAuthorityorRSGmayhavearelativelysmallMSSC.Assuch,ahighnumberof
DCSeventsgreaterthanMSSCmaynotindicateareliabilityproblemforthereportingRegional
Entity,butmayindicateanissuefortherespectiveBalancingAuthorityorRSG.Inaddition,
eventsgreaterthanMSSCmaynotcauseareliabilityissueforaBA,RSGorRegionalEntitythat
hasmorestringentstandardswhichrequirecontingencyreservegreaterthanMSSC.



Background

ReliablybalancinganInterconnectionrequiresfrequencymanagementandallofitsaspects.
InputstofrequencymanagementincludeTieͲLineBiasControl,AreaControlError(ACE),and
thevariousRequirementsinNERCResourceandDemandBalancingStandards,specificallyBALͲ
001Ͳ2RealPowerBalancingControlPerformanceandBALͲ003Ͳ1FrequencyResponseand
FrequencyBiasSetting.
BalancingContingencyEvent
BALͲ002Ͳ2appliesduringrealͲtimeoperationstoensuretheBalancingAuthorityorReserve
SharingGroupbalanceresourcesanddemandbyreturningitsAreaControlErrortodefined
valuesfollowingaReportableBalancingContingencyEvent.
ThedraftingteamincludedaspecificdefinitionforaBalancingContingencyEventtoeliminate
anyconfusionandambiguity.ThepriorversionofBALͲ002wasbroadandcouldbeinterpreted
invariouswaysleavingtheabilitytomeasurecomplianceintheeyeofthebeholder.Including
thespecificdefinitionallowstheResponsibleEntitytofullyunderstandhowtoperformand
meetcompliance.Also,FERCOrder693(atP355)directedentitiestoincludeaRequirement
thatmeasuresresponseforanyeventorcontingencythatcausesafrequencydeviation.By
developingaspecificdefinitionthatdepictstheeventscausinganunexpectedchangetothe
ResponsibleEntity’sACE,thenecessaryresponserequirementsassuretheintentoftheFERC
requirementismet.
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DisturbanceControlPerformanceͲContingencyReserveforRecoveryFromaBalancing
ContingencyEventStandardBackgroundDocument
ThedefinitionsofReportableBalancingContingencyEventandContingencyEventRecovery
PeriodworktogethertospecifythetimingrequirementsforrecoveriesfromReportable
BalancingContingencyEvents.ABalancingContingencyEventthatisnotaReportable
BalancingContingencyEventmayimpactthecompliancerequirementfortheReportable
BalancingContingencyEventwhichoccursafterit,becausethemegawattslostforbothmay
exceedtheMostSevereSingleContingency.Also,asubsequentBalancingContingencyEvent
mayoccurduringtheContingencyEventRecoveryPeriodofaReportableBalancing
ContingencyEvent,affectingtheACErecoveryrequirementoftheinitialevent.Thedrafting
teamstruggledwithassociatinganyspecifictimewindowforthemegawattlosstooccurwithin
foraneventtoqualifyasaBalancingContingencyEvent.Thetermsuddenimpliesan
unexpectedoccurrenceinthedefinitionofaBalancingContingencyEvent,andtheResponsible
EntityshoulduseitsbestjudgmentinapplyinganytimecriteriontoBalancingContingency
EventsthatdonotqualifyasReportableBalancingContingencyEvents.

MostSevereSingleContingency
TheMostSevereSingleContingency(MSSC)termhasbeenwidelyusedwithintheindustry;
however,ithasneverbeendefined.Inordertoeliminateawiderangeofdefinitions,the
draftingteamhasincludedaspecificdefinitiondesignedtofulfilltheneedsofthestandard.In
addition,inordertomeetFERCOrderNo.693(atP356),todevelopacontinentͲwide
contingencyreservepolicy,itwasnecessarytoestablishadefinitionofMSSC.
WhenanentitydeterminesitsMSSC,thereviewneedstoincludethelargestlossofresource
thatmightoccurforeithergenerationortransmissionloss.Ifthelossoftransmissioncauses
thelossofgenerationandload,thesizeofthateventwouldbethenetchange.Sincethesizeof
aneventwherebothloadandgenerationarelostduetothelossofthetransmissionwouldbe
lessthanjustthelossofthegenerator,thiseventisunlikelytobetheentity’sMSSC.Also,note
herethatthedraftingteamremovedthepreviousrequirementtoreviewtheMSSCatleast
annually.AnentityshouldknowwhatitsMSSCisatalltimes.Therefore,anannualreviewisno
longerrequired
ContingencyReserve
Mostsystemoperatorsgenerallyhaveagoodunderstandingoftheneedtobalanceresources
anddemandandreturntheirAreaControlErrortodefinedvaluesfollowingaReportable
BalancingContingencyEvent.However,theexistingContingencyReservedefinitionisfocused
primarilyongenerationandnotsufficientlyonDemandͲSideManagement(DSM).Inorderto
meetFERCOrderNo.693(atP356)toincludearequirementthatexplicitlyallowsDSMtobe
usedasaresourceforcontingencyreserve,thedraftingteamelectedtoexpandthedefinition
ofContingencyReservetoexplicitlyincludecapacityassociatedwithDSM.
Additionally,conflictexistedbetweenBALͲ002andEOPͲ002astowhenanentitycoulddeploy
orrestoreitscontingencyreserve.EOPͲ002alsoappliesduringtherealͲtimeoperationstime
horizonandaddressescapacityandenergyemergencies.Giventhatanentityand/oreventcan
transitionsuddenlyfromnormaloperations(BALͲ002)intoemergencyoperations(EOPͲ002),
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ContingencyEventStandardBackgroundDocument
thistransitionalseammustbeexplicitlyaddressedinordertoprovideclaritytoresponsible
entitiesregardingtheactionstobetaken.
ToeliminatethepossibleconflictandtoassureBALͲ002andEOPͲ002worktogetherand
complementeachother,thedraftingteamclarifiedtheexistingdefinitionofContingency
Reserve.TheconflictarisessincetheactionsrequiredbyEnergyDeficientEntitiesbefore
declaringeitheranEnergyEmergencyAlert2oranEnergyEmergencyAlert3include
deploymentofallOperatingReservewhichincludesContingencyReserve.Conversely,an
EnergyDeficientEntitymayneedtodeclareeitheranEnergyEmergencyAlert2oranEnergy
EmergencyAlert3,beforeincurringaBalancingContingencyEvent.Thedefinitionof
ContingencyReservenowallowsfordeployingcapacitytorespondtoaBalancingContingency
EventandothercontingencyrequirementssuchasEnergyEmergencyAlerts.Readinessto
reduceFirmDemandduringtheContingencyReserveRestorationPeriodduringanEnergy
EmergencyAlertshouldanotherContingencyEventoccurisproposedforinclusioninthe
definitionofContingencyReserve.TheResponsibleEntityshouldhaveprocessesand
proceduresfordirectcontrolovertheFirmDemandinplaceforittobeconsideredContingency
ReservespriortotheeventduringanEnergyEmergencyAlert.

ForadditionaltechnicaljustificationforexemptionfromR1tofacilitatetransitioningfrom
normaloperationsintoemergencyoperationspleaserefertoAttachment2.
ReserveSharingGroupReportingACE
Thedraftingteamelectedtoincludethisdefinitiontoprovideclarityformeasurementof
complianceoftheappropriateResponsibleEntity.Additionally,thisdefinitionisnecessary
sincethedraftingteamhaseliminatedR5.1andR5.2thatareintheexistingstandard.R5.1and
R5.2mixdefinitionswithperformance.Thedraftingteamhasincludedalltheperformance
requirementsintheproposedstandardsR1andR2,andthereforehasaddedthedefinitionof
ReserveSharingGroupReportingACE.
OtherDefinitions
Otherdefinitionshavebeenaddedormodifiedtoassureclarificationwithinthestandardand
requirements.


RationalebyRequirement


Requirement1
TheResponsibleEntityexperiencingaReportableBalancingContingencyEventshall:


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ContingencyEventStandardBackgroundDocument
1.1. withintheContingencyEventRecoveryPeriod,demonstraterecoveryby
returningitsReportingACEtoatleasttherecoveryvalueof:

x

zero(ifitsPreͲReportingContingencyEventACEValuewaspositiveorequal
tozero);however,anyBalancingContingencyEventthatoccursduringthe
ContingencyEventRecoveryPeriodshallreducetherequiredrecovery:(i)
beginningatthetimeof,and(ii)bythemagnitudeof,suchindividual
BalancingContingencyEvent,

or,
x

itsPreͲReportingContingencyEventACEValue(ifitsPreͲReporting
ContingencyEventACEValuewasnegative);however,anyBalancing
ContingencyEventthatoccursduringtheContingencyEventRecoveryPeriod
shallreducetherequiredrecovery:(i)beginningatthetimeof,and(ii)bythe
magnitudeof,suchindividualBalancingContingencyEvent.


1.2. documentallReportableBalancingContingencyEventsusingCRForm1.
1.3. deployContingencyReserve,withinsystemconstraints,torespondtoall
ReportableBalancingContingencyEvents,however,itisnotsubjectto
compliancewithRequirementR1part1.1if:
1.3..1 theResponsibleEntity:
x

isaBalancingAuthorityexperiencingaReliabilityCoordinatordeclared
EnergyEmergencyAlertLevelorisaReserveSharingGroupwhose
member,ormembers,areexperiencingaReliabilityCoordinator
declaredEnergyEmergencyAlertlevel,and

x

isutilizingitsContingencyReservetomitigateanoperatingemergency
inaccordancewithitsemergencyOperatingPlan,and

x

hasdepleteditsContingencyReservetoalevelbelowitsMostSevere
SingleContingency

or,
1.3.2 theResponsibleEntityexperiences:
x

multipleContingencieswherethecombinedMWlossexceedsits
MostSevereSingleContingencyandthataredefinedasasingle
BalancingContingencyEvent,or

x

multipleBalancingContingencyEventswithinthesumofthetime
periodsdefinedbytheContingencyEventRecoveryPeriodand
ContingencyReserveRestorationPeriodwhosecombinedmagnitude
exceedstheResponsibleEntity'sMostSevereSingleContingency.

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BackgroundandRationale
RequirementR1reflectstheoperatingprinciplesfirstestablishedbyNERCPolicy1.Its
objectiveistoassuretheResponsibleEntitybalancesresourcesanddemandandreturnsits
ReportableAreaControlError(ACE)todefinedvalues(subjecttoapplicablelimits)followinga
ReportableBalancingContingencyEvent.ItrequirestheResponsibleEntitytorecoverfrom
eventsthatwouldbelessthanorequaltotheResponsibleEntity’sMSSC.Itestablishes
recoveryandrestorationtimeframestheResponsibleEntitymustdemonstrateinacompliance
evaluation.Itisintendedtoeliminatetheambiguitiesandquestionsassociatedwiththe
existingstandard.Inaddition,itallowsResponsibleEntitiestohaveaclearwaytodemonstrate
complianceandsupporttheInterconnectiontothefullextentofitsMSSC.
Byincludingnewdefinitions,andmodifyingexistingdefinitions,andtheaboveR1,thedrafting
teambelievesithassuccessfullyfulfilledtherequirementsofFERCOrderNo.693(atP356)to
includearequirementthatexplicitlyallowsDSMtobeusedasaresourceforContingency
Reserve.Italsorecognizesthatthelossoftransmissionaswellasgenerationmayrequirethe
deploymentofContingencyReserve.
Additionally,R1isdesignedtoassuretheapplicableentityusesreservetocoveraReportable
BalancingContingencyEventorthecombinationofanypreviousBalancingContingencyEvents
thathaveoccurredwithinthespecifiedperiod,toaddresstheOrder’sconcernthatthe
applicableentityisrespondingtoeventsandperformanceismeasured.TheReportable
BalancingContingencyEventdefinition,alongwithR1,allowsformeasurementof
performance.
Inaddition,thestandarddraftingteam(SDT)throughR1Part1.3hasclearlyidentifiedwhenR1
isnotapplicable.ByincludingR1Part1.3.1,theproposedstandardeliminatestheexisting
conflictwiththeEOPStandardsandfurtheraddressestheoutstandinginterpretation.By
clearlystatingwhenR1isnotapplicableordoesnotapply,iteliminatesanyauditor
interpretationandallowstheResponsibleEntitytoperformthefunctioninareliablemanner.
RequirementR1doesnotapplywhenanentityexperiencesaBalancingContingencyEventthat
exceedsitsMSSC(whichincludesmultipleBalancingContingencyEventsasdescribedinR1part
1.3.2)becauseafundamentalgoaloftheSDTistoassuretheResponsibleEntityhasenough
flexibilitytomaintainservicetoloadwhilemanagingreliability.Also,theSDT’sintentisto
eliminateanypotentialoverlaporconflictwithanyotherNERCReliabilityStandardtoeliminate
duplicativereporting,andotherissues.
ThedraftingteamuseddatasuppliedbytheConsortiumforElectricReliabilityTechnology
Solutions(CERTS)tohelpdeterminealleventsthathaveanimpactonfrequency.Datathat
wascompiledbyCERTStoprovideinformationonmeasuredfrequencyeventsispresentedin
Attachment1.Analyzingthedata,revealseventsof100MWorgreaterwouldcaptureall
frequencyeventsforallinterconnections.However,ata100MWreportingthreshold,the
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ContingencyEventStandardBackgroundDocument
numberofeventsreportedwouldsignificantlyincreasewithnoreliabilitygainsince100MWis
morereflectiveoftheoutlyingevents,especiallyonlargerinterconnections.
ThegoalofthedraftingteamwastodesignacontinentͲwidestandardtocapturethemajority
oftheeventsthatimpactfrequency.Afterreviewingthedataandindustrycomments,theSDT
electedtoestablishreportingthresholdminimumsforeachrespectiveInterconnection.This
assurestherequirementsofFERCOrderNo.693aremet.Thereportablethresholdwas
selectedasthelesserof80%oftheapplicableentity’sMostSevereSingleContingencyorthe
followingvaluesforeachrespectiveInterconnection:
x
x
x
x

EasternInterconnection–900MW
WesternInterconnection–500MW
ERCOT–800MW
Quebec–500MW

Additionally,thedraftingteamusedonlylossofresourceeventsforpurposesofdetermining
theabovethresholds.
ViolationSeverityLevels
IntheViolationSeverityLevelsforRequirementR1,theimpactoftheResponsibleEntity
recoveringfromaReportableBalancingContingencyEventdependsonthepercentageof
desiredrecoveryachieved.
ComplianceCalculation
ItisimportanttonotethatR1adjuststherequiredrecoveryvalueofReportingACEforany
otherBalancingContingencyEventsthatoccurduringtheContingencyEventRecoveryPeriod.
However,todeterminecompliancescoreforcompliancewithR1,themeasuredcontingency
reserveresponse(insteadoftherequiredrecoveryvalueofReportingACE)isadjustedforany
otherBalancingContingencyEventsthatoccurduringtheContingencyEventRecoveryPeriod.
Bothmethodsofadjustmentaremathematicallyequivalent.Accordingly,themeasured
contingencyreserveresponseiscomputedandcomparedwiththeMWlostasfollows
(assumingallresourcelossvalues,i.e.BalancingContingencyEvents,arepositive)tomeasure
compliance1:
• Themeasuredcontingencyreserveresponseisequaltooneofthefollowing:

1

Inadjustingfortheadverseimpactofrapidlysucceeding(i.e.“near”)EventsonaResponsibleEntity’sRecovery

fromanEvent,theSDTthoughtitmoreprudenttoadjustforfuturenearEventsratherthanforpastnearEvents
becausethefutureEventsplaceanaddedburdenonperformance,whileadjustingforthepastEventsinstead
lowerstheperformancerequirement.ToadjustforbothfutureandpastEventsamountstodoubledealing
becauseanEventissubsequenttoapriornearEvent,andbothEventswouldbeservingtorelieveRecoveryfrom
eachother.TheSDTallowedonlyfortheextremecaseofexemptingfromrecoverypriornearEventsthat
combinedexceedMSSC.

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o IfthePreͲReportableContingencyEventACEValueisgreaterthanorequal
tozero,thenthemeasuredcontingencyreserveresponseequals(a)the
megawattvalueoftheReportableBalancingContingencyEventplus(b)the
mostpositiveACEvaluewithinitsContingencyEventRecoveryPeriod(and
followingtheoccurrenceofthelastsubsequentevent,ifany)plus(c)the
sumofthemegawattlossesofthesubsequentBalancingContingencyEvents
occurringwithintheContingencyEventRecoveryPeriodoftheReportable
BalancingContingencyEvent.
o IfthePreͲReportableContingencyEventACEValueislessthanzero,thenthe
measuredcontingencyreserveresponseequals(a)themegawattvalueof
theReportableBalancingContingencyEventplus(b)themostpositiveACE
valuewithinitsContingencyEventRecoveryPeriod(andfollowingthe
occurrenceofthelastsubsequentevent,ifany)plus(c)thesumofthe
megawattlossesofsubsequentBalancingContingencyEventsoccurring
withintheContingencyEventRecoveryPeriodoftheReportableBalancing
ContingencyEvent,minus(d)thePreͲReportableContingencyEventACE
Value.
• ComplianceiscomputedasfollowsonCRForm1inordertodocumentall
BalancingContingencyEventsusedincompliancedetermination:
ƒ

Ifthemeasuredcontingencyreserveresponseisgreaterthanor
equaltothemegawattslost,thentheReportableBalancing
ContingencyEventComplianceequals100percent.

ƒ

Ifthemeasuredcontingencyreserveresponseislessthanorequalto
zero,thentheReportableBalancingContingencyEventCompliance
equals0percent.

ƒ

Ifthemeasuredcontingencyreserveresponseislessthanthe
megawattslostbutgreaterthanzero,thentheReportableBalancing
ContingencyEventComplianceequals100%*(1–((megawattslost–
measuredcontingencyreserveresponse)/megawattslost)).


Theabovecomputationscanbeexpressedmathematicallyinthefollowing5sequentialsteps,
labeledas[1Ͳ5],where:
ACE_BEST–mostpositiveACEduringtheContingencyEventRecoveryPeriodoccurringafter
thelastsubsequentevent,ifany(MW)
ACE_PREͲPreͲReportableContingencyEventACEValue(MW)
COMPLIANCEͲReportableBalancingContingencyEventCompliancepercentage(0Ͳ100%)
MEAS_CR_RESPͲmeasuredcontingencyreserveresponsefortheReportableBalancing
ContingencyEvent(MW)
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MSSC–MostSevereSingleContingency(MW)
MW_LOSTͲmegawattlossoftheReportableBalancingContingencyEvent(MW)
SUM_SUBSQͲsumofthemegawattlossesofsubsequentBalancingContingencyEvents
occurringwithintheContingencyEventRecoveryPeriodoftheReportableBalancing
ContingencyEvent(MW)

IfACE_PREisgreaterthanorequalto0,then
MEAS_CR_RESP=MW_LOST+ACE_BEST+SUM_SUBSQ[1]

IfACE_PREislessthan0,then
MEAS_CR_RESP=MW_LOST+ACE_BEST+SUM_SUBSQ–ACE_PRE[2]

IfMEAS_CR_RESPisgreaterthanorequaltoMW_LOST,then
COMPLIANCE=100[3]

IfMEAS_CR_RESPislessthanorequalto0,then
COMPLIANCE=0[4]

IfMEAS_CR_RESPisgreaterthan0,and,MEAS_CR_RESPislessthanMW_LOST,then
COMPLIANCE=100*(1–((MW_LOST–MEAS_CR_RESP)/MW_LOST))[5]


TheDecisionTreeflowdiagramforDCSbelow,providesavisualizationofthelogicflowfora
ReportableBalancingContingencyEvent.Itincludesdecisionblocksforinitialevent
determination,subsequenteventdetermination,andcheckingforMSSCexceedance which
shouldassisttheResponsibleEntitywithEventRecoveryandanalysis.


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BAAL and
IROL

Resource Loss
> Reporting
Threshold

DCS Real
Time


DCS Off
Line
Reporting

N

Sudden?

Y

Start 15
Minute
Recovery



Subsequent
Events?

Y



N

DecisionTreeforDCS

Make Best
Efforts on
Recovery

> MSSC

Adjust
Calculations

Y

13

N

If IROL or
BAAL
Exceeded, Begin
30 Min Recover

Complete
Form

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DisturbanceControlPerformanceͲContingencyReserveforRecoveryFromaBalancing
ContingencyEventStandardBackgroundDocument

Requirement2
R2.

EachResponsibleEntityshalldevelop,reviewandmaintainannually,andimplement
anOperatingProcessaspartofitsOperatingPlantodetermineitsMostSevere
SingleContingencyandmakepreparationstohaveContingencyReserveequalto,or
greaterthantheResponsibleEntity’sMostSevereSingleContingencyavailablefor
maintainingsystemreliability.

BackgroundandRationale
R2establishesauniformcontinentͲwidecontingencyreservepolicyintheformofa
requirementthataResponsibleEntityimplementanOperatingPlanthatassuresContingency
Reservebeatleastequaltotheapplicableentity’sMostSevereSingleContingencyanda
definitionofMostSevereSingleContingency.ItsgoalistoassurethattheResponsibleEntity
willhavesufficientContingencyReservethatcanbedeployedtomeetR1.
FERCOrder693(atP356)directedBALͲ002tobedevelopedasacontinentͲwidecontingency
reservepolicy.R2fulfillstherequirementassociatedwiththerequiredamountofcontingency
reserveaResponsibleEntitymusthaveavailabletorespondtoaReportableBalancing
ContingencyEvent.WithinFERCOrder693(atP336)theCommissionnotedthatthe
appropriatemixofoperatingreserve,spinningreserveandnonͲspinningreserveshouldbe
addressed.However,theOrderpredatedtheapprovalofthenewBALͲ003,whichaddresses
frequencyresponsivereserveandtheamountoffrequencyresponseobligation.Withthe
developmentofBALͲ003,andtheassociatedreliabilityperformancerequirement,theSDT
believesthat,withR2ofBALͲ002andtheapprovalofBALͲ003,theCommission’sgoalsofa
continentͲwidecontingencyreservespolicyismet.ThesuitesofBALstandards(BALͲ001,BALͲ
002,andBALͲ003)areallperformanceͲbased.Withthesuiteofstandardsandthespecific
requirementswithineachrespectivestandard,acontinentͲwidecontingencypolicyis
established.
TheResponsibleEntity’sOperatingPlanwilladdresstheprocessbywhichContingency
ReservesgreaterthanorequaltotheMostSevereSingleContingencyareavailableinRealͲ
time.Onceanentityutilizesitscontingencyreserve,RequirementR3addressesrestorationof
thereserves.


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Requirement3
R3.

EachResponsibleEntity,followingaReportableBalancingContingencyEvent,shall
restoreitsContingencyReservetoatleastitsMostSevereSingleContingency,
beforetheendoftheContingencyReserveRestorationPeriod,butanyBalancing
ContingencyEventthatoccursbeforetheendofaContingencyReserveRestoration
periodresetsthebeginningoftheContingencyEventRecoveryPeriod.


BackgroundandRationale
RequirementR3establishestherestorationofContingencyReservesfollowingReportable
BalancingContingencyEvents.Thisrequirementaddressestheneedtobepreparedforfuture
BalancingContingencyEvents.ContingencyReservesmustberestoredtoatleasttheminimum
requiredamount,theMostSevereSingleContingency,toassurethatthenexteventforwhich
anentityplansisexpectedtobecoverediftheeventoccurs.ContingencyReservesmustbe
restoredwithintheContingencyReserveRestorationPeriodwhichisdefinedasaperiodnot
exceeding90minutesfollowingtheendoftheContingencyEventRecoveryPeriod,whichis15
minutes.






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Attachment 1
NERC Interconnections 2009-2013
Frequency Events Loss MW Statistics

For: NERC BARC Standard Drafting Team
Prepared by: CERTS
Date: October 15, 2013

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ContingencyEventStandardBackgroundDocument

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ContingencyEventStandardBackgroundDocument

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Attachment 2
Technical Justification for Applicability
of BAL-002 During Emergency Alerts

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TechnicalJustificationforApplicabilityofBALͲ002
DuringEnergyEmergencyAlerts

I.

INTRODUCTION


TheBalancingAuthorityReliabilityͲbasedControlsstandarddraftingteam(BARCSDT)has
identifiedaconflictbetweenNERCReliabilityStandardsBALͲ002andEOPͲ002that
unnecessarilyrequiresarbitraryinterruptionofFirmLoad.Inordertoaddressthisissue,the
BARCSDTisrecommendingthatStandardBALͲ002Ͳ2notbeenforceableduringanEnergy
EmergencyAlert(EEA)eventwheretheEEAprocessrequirestheuseofContingencyReserveto
maintainloadservice.2Thisdocumentprovidessupportforthisrecommendationandan
overviewofreliablefrequencymanagementontheNorthAmericanInterconnections.

II.
BACKGROUND

ReliablybalancinganInterconnectionrequiresfrequencymanagementandallofitsaspects.
InputstofrequencymanagementincludeTieͲLineBiasControl,AreaControlError(ACE),and
thevariousRequirementsinNERCResourceandDemandBalancingStandards,specificallyBALͲ
001Ͳ2RealPowerBalancingControlPerformanceandBALͲ003Ͳ1FrequencyResponseand
FrequencyBiasSetting.

ReliabilityStandardBALͲ002appliesduringtherealͲtimeoperationstimehorizonand
addressesthebalancingofresourcesanddemandfollowingadisturbance.ReliabilityStandard
EOPͲ002alsoappliesduringtherealͲtimeoperationstimehorizonandaddressescapacityand
energyemergencies.Giventhatanentityand/oreventcantransitionsuddenlyfromnormal
operationsintoemergencyoperations(EOPͲ002)whereContingencyReservemaintainedunder
BALͲ002maybeutilizedtoserveFirmLoad,thistransitionalseammustbeexplicitlyaddressed
inordertoprovideclaritytoresponsibleentitiesregardingtheactionstobetaken.The
proposedapplicabilityofBALͲ002isdesignedtoaddressthisissue.

III.
LEGACYREQUIREMENTS

TheResourceandDemandBalancing(BAL)standardsincludebothrequirementsthathavea
soundtechnicalbasisandlegacyrequirementsthattheindustryhasusedforyearsbutfailto

2

Theproposedapplicabilitysectionstates:“ApplicabilityisdeterminedonanindividualReportableBalancing
ContingencyEventbasis,buttheResponsibleEntityisnotsubjecttocomplianceduringperiodswhenthe
ResponsibleEntityisinanEnergyEmergencyAlertLevelunderwhichContingencyReserveshavebeenactivated.”
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haveasoundtechnicalbasis.NERCbeganreplacingtheselegacyrequirementswithtechnically
basedrequirementsstartingwiththeControlPerformanceStandard1(CPS1).BothControl
PerformanceStandard2(CPS2)andtheDisturbanceControlStandard(DCS)remaininthe
legacycategory.Thefollowingarespecificconcernsassociatedwiththeserequirements.
o WhenCPS1wasimplementedtoreplaceA1/A2,previousrequirementswere
modifiedsothatCPS1wouldapplyatalltimesincludingthe(disturbance)
periodswhereDCSisapplicable,notjustduringnormaloperations/periods.So
DCSisnottheonlystandardgoverningdisturbanceconditions.
o TheDisturbanceControlStandard(DCS)anditsprecursorB1/B2havebeen
uniqueinrequiringimmediateactionbytheBalancingAuthority(BA),inthis
casetoaddressunexpectedimbalanceswithindefinedlimits.
o DCS,albeitresultsͲbasedinitscurrentform,wasinitiallydesignedtomeasure
theutilizationofContingencyReservetoaddressalossofresourcewithinthe
definedlimits.InitsresultsͲbasedformitassumedthatimplementingsufficient
ContingencyReservesasneededtocomplywiththerecoveryrequirement
wouldbeareasonablyequitableminimumquantityforallBAsparticipatingin
interconnectedoperation.
o DCSisbaseduponACErecoverytothelowerofpreͲdisturbanceACEorzero.A
BalancingAuthoritywhichmightbeunderͲgeneratingpriortoagenerationloss,
couldloseageneratingunitandunderDCSbedeemedcompliantifitreturned
ACEtoitspreͲdisturbancestate,thoughitcouldstillbedepressing
Interconnectionfrequency.
o AsDCSrecoveryfromareportableeventmustoccurwithina15Ͳminuteperiod,
itispossibleforaBalancingAuthority’sACEtoagaingonegativeafterthattime,
withasimilarimpactonInterconnectionfrequency.
o SinceCPS2allowsaBAtobeunaccountableforapproximately74hoursof
operationina31Ͳdaymonth,animbalanceconditionmaypersistandnegatively
impactInterconnectionfrequencyformanyhours3.
o WhenACEismodulatedbyfrequency,“significant”lossesaredefinednotonly
bythesizeoftheeventcausinganACEdeviation,butalsocontingentonthe
deviationofInterconnectionfrequencyfromScheduledFrequency.

IV.
TIEͲLINEBIASFREQUENCYCONTROLANDACE


3

ReliabilityͲBasedControlv3,StandardAuthorizationRequestForm,November7,2007.

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TieͲLineBiasFrequencyControlisimplementedontheNorthAmericanInterconnections
throughtheuseoftheACEEquation.4Ingeneral,ACEisthetermusedtodeterminetheloadͲ
generationimbalancethatisbeingcontributedbyeachBalancingAuthority(BA)onan
Interconnection.ACEisapowerfulindicator,becauseitindicatestheimbalancewithinthe
boundariesofasingleBA,thusdefiningtheSecondaryControlresponsibilitiesforthatBAand,
therefore,thecontrolactionthatwouldreturnACEtozero.ACEincludestheFrequencyBias
Settingterm,whichallowsthePrimaryFrequencyControltobeasharedservicethroughouta
multiͲBAInterconnection,whileassigningtoeachindividualBAthespecificresponsibilitiesof
maintainingitsownSecondaryFrequencyControl.

Insummary,ACEonlyprovidesguidancewithrespecttoSecondaryFrequencyControland
doesnotindicateorprovideanydirectmeasureofPrimaryFrequencyControl,andonlyreflects
theestimatedFrequencyResponseasrepresentedbytheFrequencyBiasSettingterm.NERC
RequirementsandsupportingdocumentationforFrequencyResponse(PrimaryFrequency
Control)areincludedinBALͲ003Ͳ1FrequencyResponseandFrequencyBiasSettingstandard.
MoredetailonTieͲLineBiasFrequencyControlandACEisattached.5

V.
CONTROLPERFORMANCESTANDARD1(CPS1)

PriortothedevelopmentofCPS1,theindustryassumedthat,"Itisimpossible,however,to
usefrequencydeviationtoidentifythespecificcontrolarea(sic,i.e.BA)withtheunderͲor
overͲgenerationcreatingthefrequencydeviation…".3Inthe1990'sthedevelopmentofCPS1
demonstratedthatnotonlywasitpossibletoidentifythespecificBAcreatingthefrequency
deviation,butthatitisalsopossiblenotonlytodeterminetherelativecontributionbyeachBA
tothemagnitudeofthefrequencydeviation6,butalsotodeterminetherelativecontributionof
eachBAtothereliabilityriskcausedbythatdeviation.Inaddition,theCPS1Requirement
providedaguarantee:"IfallBAsonaninterconnectioncompliedwiththeCPS1Requirement,

4

Illian,HowardF.,UnderstandingACE,CPS1andBAAL,PreparedfortheNERCBARCStandardDraftingTeam,
September10,2010rev.August19,2014,Section2,pp.1Ͳ4,foraderivationoftheACEEquationandthe
requirementsforimplementingitthatareincludedinthedefinitionofACEappearingintheNERCGlossary.

5

Illian, Howard F., Frequency Control Performance Measurement and Requirements, Ernest
Orlando Lawrence Berkeley National Laboratory, December 2010, for a discussion of the
history of Frequency Control and Performance Measurement.

6

Illian, Howard F., Understanding ACE, CPS1 and BAAL, Section 2, pp. 5-10 for a derivation
of the CPS1 requirement.

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theRootMeanSquared7valueofthefrequencydeviationforthatInterconnectionwouldbe
lessthantheepsilon18frequencydeviationlimitforthatInterconnection."

CPS1isarollingannualaverageofindividualmeasurementseachaveragedoveroneͲ
minute,andisassessedmonthly.CPS1measuresthecovariancebetweentheACEofaBAand
thefrequencydeviationoftheInterconnectionwhichisequaltothesumoftheACEsofallof
theBAs.CPS1hasthegreatvalueofusingtheInterconnectionfrequencytodeterminethe
degreetowhichACEamongtheBAsonamultipleBAInterconnectionisharmingorhelping
interconnectionfrequency.Sincethefrequencydeviationisameasuredvalue,theACEofaBA
willdirectlyaffectonlytheCPS1oftheBAwiththeACEandnottheCPS1measureofotherBAs.

VI.
BALANCINGAUTHORITYACELIMIT(BAAL)

WhentheBalancingResourcesandDemand(BRD)standarddraftingteamrecognizedthe
needforacontrolmeasureoverashortertimehorizonthaneitherCPS1(annual)orControl
PerformanceStandard29(CPS2,monthly)provided,itbeganlookingforameasurethatwould
allowawindowforcommonimbalanceeventslikeaunittrip,whileprovidingalimitonhow
muchfrequencydeviationshouldbeallowedoverthatshortperiod.Afterconsidering
numerousalternatives,BAALwasselectedastheappropriateshortͲtermmeasure.10,11


7

“Root Mean Squared” means the square root of the mean of the squared errors, so that
positive and negative errors do not offset each other and any shift in the mean is counted
as error.

8

“Epsilon1” is the frequency deviation limit determined for each North American
Interconnection and used by CPS1 to bound the Root Mean Squared frequency deviation.
It is 18 mHz on the Eastern, 22.8 mHz on the Western, 30 mHz on the ERCOT, and 21
mHz on the Quebec Interconnections.

9

Proposed to be replaced by BAAL under BAL-001-2, CPS2 requires the BA to move its ACE
within predefined L10 bounds when it is binding (during only 90% of the ten-minute
periods per month) without regard to whether such action helps or hurts Interconnection
frequency.

10

Illian, Howard F., Meeting the Discrete Event Measure (DEM) Objectives with the
Abnormal Operations Measure (AOM), Prepared for the NERC Balancing Resources and
Demand Standard Drafting Team, March 20, 2004.

11

Illian, Howard F., Setting the Balancing Authority ACE Limit (BAAL) for the NERC
Abnormal Operations Measure (AOM), Prepared for the NERC Balancing Resources and
Demand Standard Drafting Team, March 28, 2004.

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ConsiderableevaluationandFieldTrialshaveshownthatBAAL12isabetterindicatorof
contributionstoreliabilityriskofaninterconnectionthanthemagnitudeofACEalone.This
superiority,likeCPS1’s,derivesfromtheconcurrentuseofbothACEandfrequencyerrorinthe
BAALmeasure.ThusBAALcapturestherelativecontributiontoreliabilitybyalloftheACEson
aninterconnectionandindicateswhereeachBAstandsrelativetoitssecondarycontrol
responsibilitiesandthecurrentstateoftheinterconnectionasindicatedbythefrequencyerror
forbothunderͲandoverͲfrequencyconditions.

VII.
INTERACTIONBETWEENSTANDARDS

Thedraftingteamhasidentifiedasanissuetheexistenceofpointswherethestandardsare
inconflictwitheachother.Thedraftingteamhasattemptedtoaddresstheconflictsidentified,
asfollows:

NERCstandardEOPͲ002requiresaBAtouseallitsreservesduringanEnergyEmergency
Alert2(EEA2)orhigher.ThefollowinglanguageisfoundinEOPͲ002Attachment1ͲEOPͲ002:
2.6.4OperatingReserves.Operatingreservesarebeingutilizedsuchthatthe
EnergyDeficientEntityiscarryingreservesbelowtherequiredminimumor
hasinitiatedemergencyassistancethroughitsoperatingreservesharing
program.

ThecurrentBALͲ002specifiesaminimumlevelreserverequirementatalltimesunlessa
qualifyingeventhasoccurred.ThedraftingteamnotedthatintheEEAprocessanentityis
driventorequestanEEArarelyastheresultofasingleunitloss.Infact,anEEAdeclarationby
theReliabilityCoordinatormightresultfromissuesthatincludenoeventthatwouldqualifyas
aDisturbanceandtheEEAsituationcouldlastlongerthanthereserverecoveryperiodof90
minutes.Forthisreason,thedraftingteamrecommendssignificantchangestothestandardsin
question.

Inadditiontotheidentifiedconflict,otherstandardscanrequiretheactivationof
contingencyreserve.TheseincludeotherBALstandards,IROstandardsandTOPstandards.
Comparedtothosestandards,theBALͲ002standardprovidestheleastdirectmeasureof
reliability.Therefore,anentityshouldneverbeconflictedbetweenapplyingtherequirements
ofBALͲ002andcomplyingwiththeotherstandards.


12

Illian, Howard F., Understanding ACE, CPS1 and BAAL, Prepared for the NERC BARC
Standard Drafting Team, September 10, 2010 rev. August 19, 2014, Section 2, pp. 10, for
a derivation of the BAAL requirement.

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Finally,thereisoneoverarchingprincipalnotreflectedinthediscussionuptothispoint,
namelykeepingthelightsonifpossible.IfthereisarequirementtobringACEbacknomatter
what,thenthatrequirementwillhavetheunintendedconsequenceofsheddingFirmLoad,
especiallyduringanEEA.DuringtheEEAprocess,theexpectationisthataBAwillhavefirm
loadreadytoshedinordertomeetitsreserverequirementunderR2oftheproposedBALͲ002
standard.However,iftheBALͲ002standardalsorequirestheentitytomeetR1duringtheEEA,
entitieswillshedfirmloadtorestoreACEtoitspreͲcontingencylevel,regardlessofthelackof
anyreliabilityissues.Inotherwords,frequencycouldbesettlingatorverynear60Hz,no
transmissionlinesareoverloadedasdeterminedbytheTOPstandards,andtheentityis
operatingwithintheparametersdefinedinBALͲ001,butfirmloadwouldbeinterruptedsimply
tobringtheentity’sACEbacktowhatitwaspriortothelossoftheunit.Sincetheindustryhas
definedreliabilityasfrequencyatornear60Hzandtransmissionlinesoperatingwithintheir
limits,thereisnoreasontointerruptfirmload.

Instead,theBARCSDTisrecommendingthatStandardBALͲ002Ͳ2notbeenforceable
duringanEEAeventwheretheEEAprocessrequirestheuseofContingencyReserveto
maintainloadservice.Instead,theReliabilityCoordinator,TransmissionOperatorsandthe
impactedBalancingAuthoritiesshoulduserealͲtimesituationalawareness,takingintoaccount
issuesaddressedinBALͲ001,BALͲ003,theIROsuiteofstandardsandtheTOPsuiteof
standards,todeterminewhatactionsareappropriatewhenconditionsareabnormal.This
processwouldallowcontinuedloadservicewithoutarbitrarilyrequiringinterruptionoffirm
load.

Thisconcernarisesbecausetheotherstandardslookatspecificreliabilityissuesother
thanjustbalancingbetweenscheduledandactualinterchange.BALͲ001Ͳ2andBALͲ003Ͳ1look
atinterconnectionfrequencytodeterminewhethertheBalancingAuthorityishelpingor
hurtingreliability.DuringanEEAevent,curtailingloadtomoveACEbacktoapreͲeventlevel
couldadverselyaffectfrequency.Iffrequencygoesupfrom60HzwhenaBalancingAuthority
interruptsload,theimpactisdetrimentaltotheinterconnection.UndertheTOPstandards,if
flowsontransmissionlinesarewithinthelimitsspecified,thereisnoneedtoaltertheflowson
thetransmissionsystembyinterruptingload.

Finally,theReliabilityCoordinatorhasawideareaviewoftheelectricsystemas
requiredundertheIROstandards.TheIROstandardsclearlystatetheReliabilityCoordinator’s
responsibilitiesduringtheEEAprocess.IftheReliabilityCoordinatorhasnotidentifieda
reliabilityconcerninitsneartermoperationsevaluation,actionssuchasinterruptionoffirm
loadshouldnotoccursimplytobalanceloadandresourceswithintheBA.Duringabnormal
(emergency)situations,takingsignificantactionswithanarrowviewwillnotbebeneficialfor
Interconnectionreliability.

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EXAMPLES
o Example1
OnanusuallycolddayinFebruary2011,at06:22,aBalancingAuthorityArea
(BAA)experienceda350MWgenerationlosswhena750MWjointownership
unittrippedoffͲline.EarlierinthedaytheBAAoperatorexperiencedlossof
severalgeneratingunitswithatotalcapacityof1050MW,thelatestlossbeing
just38minutespriortothe350MWloss.Whenthe350MWeventoccurred
theBAAoperatorrequestedreserve/emergencyassistance,shed300MWof
customerloadtorestorecontingencyreserve,andrequestedtheRCpostan
EEA3.TheEEA3wasposted.Althoughthefrequencyonlytouched59.91Hz,
averaging59.951Hzinthefirstminuteoftheoutage,wasitreallynecessaryto
cutloadandleavepeopleinthecold,darkofthatmorningtorestore
contingencyreserve?Havingidlegeneration,whentheInterconnectionis
operatingreliably,doesnotwarrantsheddingcustomerload.
o Example2
InJune2012,at17:08,aBAAexperiencedan800MWgenerationloss.TheBA
andthereservesharinggroup(RSG)itparticipatesinwereintheprocessof
replacingthelostgenerationwhen,inthethirteenthminuteoftherecovery
whentherewerenoidentifiedfrequency,voltageorloadingthreatstoreliability,
theBAAwasdirectedbyitsReliabilityCoordinator(RC)toshed120MWof
customerload.AlthoughthecombinedAreaControlError(ACE)oftheRSG
participantswaspositive,theRCfocusedontheACEoftheBAAthatlostthe
generation–whichwasstillnegative–ignoringthefactthattheInterconnection
frequency(59.96Hz)wasabovetheFrequencyTriggerLimit(59.932Hz).The
needlesssheddingofcustomerloadwhensystemreliabilityisnotthreatened
attractedtheattentionofstateregulatorswhowerenothappywiththeaction.
ThisdemonstratesthatfocusingsolelyonaBAA’sACEandnotonthetrue
Interconnectionreliabilityindicatorscancauseactionsthatdonotsupport
reliability.
o Example3
InJune2004,at0741,aseriesofeventsledtoagenerationlossofover4,600
MW.Inspiteoftheeventsize,theInterconnectionfrequencywasarrested
withouttriggeringautomaticunderfrequencyloadshedding,thankstogovernor
action,frequencysensitiveloadanddeploymentofContingencyReserve(as
requiredbyBALͲ002).Sometransmissionelementsexceededtheirlimitsfora
shorttime(aspermittedbytheEOPstandards),And,priortothedisturbance,
thefrequencywasinthenormaloperatingrangeduetoautomaticgeneration
control(AGC)operation(asrequiredbyBALͲ001).Duringtheeventalmost1,000
MWofinterruptiblecustomerloadwasshedthroughouttheinterconnected
systemsbydevicesthatautomaticallyoperatedtoprotectvariouspartsofthe
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system(asdeterminedbytheTPLandTOPStandards).Thisdemonstrateshow
thesuiteofstandardsdefinedbyNERCworktogethertoefficientlyprotectthe
systemandminimizecustomerinterruptions.

CONCLUSIONS

VIII.

Thereareimportantconclusionsthatcanbedrawnfromthisworkandthe
mathematicalguaranteesthatitprovides:

o TheDisturbanceControlStandard(DCS)ascurrentlyconfiguredonlylooksat
ACE,theimbalancecontributionofasingleBA,anddoesnotincludeaspecific
frequencyerrorcomponentthatindicatestheBA’scontributionrelativetothe
conditionoftheinterconnectiontowhichtheBAisconnected.

o AstheDCSmeasuredoesnothaveaspecificfrequencycomponent,compliance
toDCSattimesconflictswiththeoverallgoaloftargetingoperationwithin
predefinedInterconnectionfrequencylimits.Forexample,DCSrecoveryinitiated
fromaboveScheduledFrequencyhasadetrimentalimpactonInterconnection
frequency.

o ThefocusonACEaloneisinsufficienttocontrolfrequencyonamultipleBA
Interconnection.ThecorrelationoftheACEsamongtheBAsonthe
Interconnectionwillaffectthequalityoffrequencycontrolindependentofhow
anyindividualACEiscontrolled.

o AdequatecontrolofInterconnectionfrequencyrequirestheuseofbothACE
(individualBAbalancingerror)andfrequencydeviation.

o AdequatecontrolofreliabilityriskonanInterconnectionrequirestheuseof
ACE,frequencydeviationandavailablefrequencyresponse.

o BAALaddressesalleventsimpactingInterconnectionfrequency,bothaboveand
belowscheduledfrequency.

BAALaddressesalloftheaboveissuesinitstimedomainwithoutrequiringresponsetoor
measurementofeventsthatfailtoraisereliabilityconcerns.Forthesereasons,theproposed
applicabilityofBALͲ002isareasonableandtechnicallyͲjustifiedapproachthataddressesthe
seamwithEOPͲ002.

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Table of Contents
Introduction .................................................................................................................................... 3
RationalebyRequirement .............................................................................................................. 7
Requirement1 ............................................................................................................................ 7
Requirement2 .......................................................................................................................... 14
Requirement3 .......................................................................................................................... 15


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Introduction
TherevisiontoNERCPolicyStandardsin1996createdaDisturbanceControlStandard(DCS).It
replacedB1[AreaControlError(ACE)mustreturntozerowithin10minutesfollowinga
disturbance]andB2(ACEmuststarttoreturntozeroin1minutefollowingadisturbance)with
astandardthatstates:ACEmustreturntoeitherzeroorapreͲdisturbancevalueofACEwithin
15minutesfollowingareportabledisturbance.BalancingAuthoritieswererequiredtoreport
alldisturbancesequaltoorgreaterthan80%oftheBalancingAuthority’sMostSevereSingle
Contingency(MSSC).

BALͲ002wascreatedtoreplaceportionsofPolicy1.Itmeasurestheabilityofanapplicable
entitytorecoverfromareportableeventwiththedeploymentofreserve.Thereliable
operationoftheinterconnectedpowersystemrequiresthatadequatecapacityandenergybe
availabletomaintainscheduledfrequencyandavoidlossoffirmloadfollowinglossof
transmissionorgenerationcontingencies.Thiscapacity(ContingencyReserve)isnecessaryto
replacecapacityandenergylostduetoforcedoutagesofgenerationortransmission
equipment.ThedesignofBALͲ002andPolicy1waspredicatedontheInterconnection’s
operatingundernormalconditions,andtherequirementsofBALͲ002assuredrecoveryfrom
singlecontingency(NͲ1)events.

ThisdocumentprovidesbackgroundonthedevelopmentandimplementationofBALͲ002Ͳ2Ͳ
ContingencyReserveforRecoveryfromaBalancingContingencyEvent.Thisdocumentexplains
therationaleandconsiderationsfortherequirementsandtheirassociatedcompliance
information.BALͲ002Ͳ2wasdevelopedtofulfilltheNERCBalancingAuthorityControls(Project
2007Ͳ05)StandardAuthorizationRequest(SAR),whichincludestheincorporationoftheFERC
Order693directives.TheoriginalSAR,approvedbytheindustry,presumesthereispresently
sufficientContingencyReserveinalltheNorthAmericanInterconnections.Theunderlyinggoal
oftheSARwastoupdatethestandardtomakethemeasurementprocessmoreobjectiveand
toprovideinformationtotheBalancingAuthorityorReserveSharingGroup,suchthatthe
partieswouldbetterunderstandtheuseofContingencyReservetobalanceresourcesand
demandfollowingaReportableBalancingContingencyEvent.

Currently,theexistingBALͲ002Ͳ1standardcontainsRequirementsspecifictoaReserveSharing
Groupwhichthedraftingteambelievesarecommercialinnatureandacontractual
arrangementbetweenthereservesharinggroupparties.BALͲ002Ͳ2isintendedtomeasurethe
successfuldeploymentofcontingencyreservebyresponsibleentities.Relationshipsbetween
theentitiesshouldnotbepartoftheperformancerequirements,butleftuptoacommercial
transaction.
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Clarityandspecificsareprovidedwithseveralnewdefinitions.Additionally,theBALͲ002Ͳ2
eliminatesanyquestionaboutwhoistheapplicableentityandassuresthattheapplicable
entityisheldresponsiblefortheperformancerequirement.Thedraftingteam’sgoalwasto
haveBALͲ002Ͳ2besolelyaperformancestandard.TheprimaryobjectiveofBALͲ002Ͳ2isto
ensurethattheapplicableentityispreparedtobalanceresourcesanddemandandtoreturnits
ACEtodefinedvalues(subjecttoapplicablelimits)followingaReportableBalancing
ContingencyEvent.

Asproposed,thisstandardisnotintendedtoaddresseventsgreaterthanaResponsibleEntity’s
MostSevereSingleContingency.TheselargemultiͲunitevents,althoughunlikely,dooccur.
ManyinteractionsoccurduringtheseeventsandBalancingAuthorities(BAs)andReserve
SharingGroupsmustreacttotheseevents.However,requiringarecoveryofACEwithina
specifictimeperiodismuchtoosimpleamethodologytoadequatelyaddressallofthese
interactions.ThesuiteofNERCStandardsworktogethertoensurethattheInterconnections
areoperatedinasafeandreliablemanner.Itisnotjustonestandard,ratheritisthe
combinationoftheBALͲ001Ͳ2standard(inwhichR2requiresoperationwithinanACE
bandwidthbasedoninterconnectionfrequency),TOPͲ007,andEOPͲ002,whichcollectively
addressissueswhenlargeeventsoccur.
x

TheBalancingAuthorityACELimit(BAAL)inR2ofBALͲ001Ͳ2looksatInterconnection
frequencytoprovidetheBAarangeinwhichtheBAshouldstrivetooperateaswellas
a30ͲminuteperiodtoaddressinstanceswhentheBAisoutsideofthatrange.Ifan
eventlargerthantheBA’sMSSCoccurs,theBAALwilllikelychangetoamuchtighter
controllimitbasedonthechangeininterconnectionfrequency.The30Ͳminutelimit
undertheBAALallowstheBA(anditsRC)timetoquicklyevaluatethebestcourseof
actionandthenreactinareasonablemanner.BAALalsoensurestheResponsibleEntity
balancesresourcesanddemandwheneventsoccuroflessmagnitudethanaReportable
BalancingContingency.InadditionR1ofBALͲ001Ͳ2requirestheBAtorespondto
assureControlPerformanceStandard1(CPS1)ismet.ThismayprompttheBAto
respondinsomecircumstancesinlessthan10minutes.

x

TheTOPͲ007standardaddressestransmissionlineloading.MembersoftheBALͲ002Ͳ2
draftingteamareawareofinstances(typicallyNͲ2orless)thatcouldcausetransmission
overloadsifcertainunitswerelostandreservesresponded.

x

UnderEOPͲ002,iftheBAdoesnotbelievethatitcanmeetcertainparameters,different
rulesareimplemented.

Becauseofthepotentialforsignificantunintendedconsequencesthatcouldoccurundera
requirementtoactivateallreserves,thedraftingteamrecommendstotheindustrythatthe
revisedBALͲ002Ͳ2addressonlyeventswhichareplannedfor(NͲ1)andnotanylossof
resource(s)thatwouldexceedMSSC.Therefore,thedefinitionsandRequirementsunderBALͲ
002Ͳ2excludeeventsgreaterthantheMSSC.ThisprovidesclarityofRequirements,supports
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reliableoperationoftheBulkElectricSystemandallowsotherstandardstoaddresseventsof
greatermagnitudeandcomplexity.

WithinNERC’sStateofReliabilityReport,ALR2Ͳ5“DisturbanceControlEventsGreaterThanthe
MostSevereSingleContingency”hasbeentrackedandreportedsince2006.Fortheperiod
2006to2011therewere90disturbanceeventsthatexceededtheMSSC,withthehighestin
anygivenyearbeing24events.EvaluationofthedataillustrateseventsgreaterthanMSSC
occurveryinfrequently,andthedraftingteambelievestheirexclusionwillnothaveany
adverseimpactonreliability.

ThemetricreportsthenumberofDCSeventsgreaterthanMSSC,regardlessofthesizeofa
BalancingAuthorityorRSGandofthenumberofreportingentitieswithinaRegionalEntity.A
smallBalancingAuthorityorRSGmayhavearelativelysmallMSSC.Assuch,ahighnumberof
DCSeventsgreaterthanMSSCmaynotindicateareliabilityproblemforthereportingRegional
Entity,butmayindicateanissuefortherespectiveBalancingAuthorityorRSG.Inaddition,
eventsgreaterthanMSSCmaynotcauseareliabilityissueforaBA,RSGorRegionalEntitythat
hasmorestringentstandardswhichrequirecontingencyreservegreaterthanMSSC.



Background

ReliablybalancinganInterconnectionrequiresfrequencymanagementandallofitsaspects.
InputstofrequencymanagementincludeTieͲLineBiasControl,AreaControlError(ACE),and
thevariousRequirementsinNERCResourceandDemandBalancingStandards,specificallyBALͲ
001Ͳ2RealPowerBalancingControlPerformanceandBALͲ003Ͳ1FrequencyResponseand
FrequencyBiasSetting.
BalancingContingencyEvent
BALͲ002Ͳ2appliesduringrealͲtimeoperationstoensuretheBalancingAuthorityorReserve
SharingGroupbalanceresourcesanddemandbyreturningitsAreaControlErrortodefined
valuesfollowingaReportableBalancingContingencyEvent.
ThedraftingteamincludedaspecificdefinitionforaBalancingContingencyEventtoeliminate
anyconfusionandambiguity.ThepriorversionofBALͲ002wasbroadandcouldbeinterpreted
invariouswaysleavingtheabilitytomeasurecomplianceintheeyeofthebeholder.Including
thespecificdefinitionallowstheResponsibleEntitytofullyunderstandhowtoperformand
meetcompliance.Also,FERCOrder693(atP355)directedentitiestoincludeaRequirement
thatmeasuresresponseforanyeventorcontingencythatcausesafrequencydeviation.By
developingaspecificdefinitionthatdepictstheeventscausinganunexpectedchangetothe
ResponsibleEntity’sACE,thenecessaryresponserequirementsassuretheintentoftheFERC
requirementismet.
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ThedefinitionsofReportableBalancingContingencyEventandContingencyEventRecovery
PeriodworktogethertospecifythetimingrequirementsforrecoveriesfromReportable
BalancingContingencyEvents.ABalancingContingencyEventthatisnotaReportable
BalancingContingencyEventmayimpactthecompliancerequirementfortheReportable
BalancingContingencyEventwhichoccursafterit,becausethemegawattslostforbothmay
exceedtheMostSevereSingleContingency.Also,asubsequentBalancingContingencyEvent
mayoccurduringtheContingencyEventRecoveryPeriodofaReportableBalancing
ContingencyEvent,affectingtheACErecoveryrequirementoftheinitialevent.Thedrafting
teamstruggledwithassociatinganyspecifictimewindowforthemegawattlosstooccurwithin
foraneventtoqualifyasaBalancingContingencyEvent.Thetermsuddenimpliesan
unexpectedoccurrenceinthedefinitionofaBalancingContingencyEvent,andtheResponsible
EntityshoulduseitsbestjudgmentinapplyinganytimecriteriontoBalancingContingency
EventsthatdonotqualifyasReportableBalancingContingencyEvents.

MostSevereSingleContingency
TheMostSevereSingleContingency(MSSC)termhasbeenwidelyusedwithintheindustry;
however,ithasneverbeendefined.Inordertoeliminateawiderangeofdefinitions,the
draftingteamhasincludedaspecificdefinitiondesignedtofulfilltheneedsofthestandard.In
addition,inordertomeetFERCOrderNo.693(atP356),todevelopacontinentͲwide
contingencyreservepolicy,itwasnecessarytoestablishadefinitionofMSSC.
WhenanentitydeterminesitsMSSC,thereviewneedstoincludethelargestlossofresource
thatmightoccurforeithergenerationortransmissionloss.Ifthelossoftransmissioncauses
thelossofgenerationandload,thesizeofthateventwouldbethenetchange.Sincethesizeof
aneventwherebothloadandgenerationarelostduetothelossofthetransmissionwouldbe
lessthanjustthelossofthegenerator,thiseventisunlikelytobetheentity’sMSSC.Also,note
herethatthedraftingteamremovedthepreviousrequirementtoreviewtheMSSCatleast
annually.AnentityshouldknowwhatitsMSSCisatalltimes.Therefore,anannualreviewisno
longerrequired
ContingencyReserve
Mostsystemoperatorsgenerallyhaveagoodunderstandingoftheneedtobalanceresources
anddemandandreturntheirAreaControlErrortodefinedvaluesfollowingaReportable
BalancingContingencyEvent.However,theexistingContingencyReservedefinitionisfocused
primarilyongenerationandnotsufficientlyonDemandͲSideManagement(DSM).Inorderto
meetFERCOrderNo.693(atP356)toincludearequirementthatexplicitlyallowsDSMtobe
usedasaresourceforcontingencyreserve,thedraftingteamelectedtoexpandthedefinition
ofContingencyReservetoexplicitlyincludecapacityassociatedwithDSM.
Additionally,conflictexistedbetweenBALͲ002andEOPͲ002astowhenanentitycoulddeploy
orrestoreitscontingencyreserve.EOPͲ002alsoappliesduringtherealͲtimeoperationstime
horizonandaddressescapacityandenergyemergencies.Giventhatanentityand/oreventcan
transitionsuddenlyfromnormaloperations(BALͲ002)intoemergencyoperations(EOPͲ002),
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thistransitionalseammustbeexplicitlyaddressedinordertoprovideclaritytoresponsible
entitiesregardingtheactionstobetaken.
ToeliminatethepossibleconflictandtoassureBALͲ002andEOPͲ002worktogetherand
complementeachother,thedraftingteamclarifiedtheexistingdefinitionofContingency
Reserve.TheconflictarisessincetheactionsrequiredbyEnergyDeficientEntitiesbefore
declaringeitheranEnergyEmergencyAlert2oranEnergyEmergencyAlert3include
deploymentofallOperatingReservewhichincludesContingencyReserve.Conversely,an
EnergyDeficientEntitymayneedtodeclareeitheranEnergyEmergencyAlert2oranEnergy
EmergencyAlert3,beforeincurringaBalancingContingencyEvent.Thedefinitionof
ContingencyReservenowallowsfordeployingcapacitytorespondtoaBalancingContingency
EventandothercontingencyrequirementssuchasEnergyEmergencyAlerts.Readinessto
reduceFirmDemandduringtheContingencyReserveRestorationPeriodduringanEnergy
EmergencyAlertshouldanotherContingencyEventoccurisproposedforinclusioninthe
definitionofContingencyReserve.TheResponsibleEntityshouldhaveprocessesand
proceduresfordirectcontrolovertheFirmDemandinplaceforittobeconsideredContingency
ReservespriortotheeventduringanEnergyEmergencyAlert.

ForadditionaltechnicaljustificationforexemptionfromR1tofacilitatetransitioningfrom
normaloperationsintoemergencyoperationspleaserefertoAttachment2.
ReserveSharingGroupReportingACE
Thedraftingteamelectedtoincludethisdefinitiontoprovideclarityformeasurementof
complianceoftheappropriateResponsibleEntity.Additionally,thisdefinitionisnecessary
sincethedraftingteamhaseliminatedR5.1andR5.2thatareintheexistingstandard.R5.1and
R5.2mixdefinitionswithperformance.Thedraftingteamhasincludedalltheperformance
requirementsintheproposedstandardsR1andR2,andthereforehasaddedthedefinitionof
ReserveSharingGroupReportingACE.
OtherDefinitions
Otherdefinitionshavebeenaddedormodifiedtoassureclarificationwithinthestandardand
requirements.


RationalebyRequirement


Requirement1
TheResponsibleEntityexperiencingaReportableBalancingContingencyEventshall:


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1.1. withintheContingencyEventRecoveryPeriod,demonstraterecoveryby
returningitsReportingACEtoatleasttherecoveryvalueof:

x

zero(ifitsPreͲReportingContingencyEventACEValuewaspositiveorequal
tozero);however,anyBalancingContingencyEventthatoccursduringthe
ContingencyEventRecoveryPeriodshallreducetherequiredrecovery:(i)
beginningatthetimeof,and(ii)bythemagnitudeof,suchindividual
BalancingContingencyEvent,

or,
x

itsPreͲReportingContingencyEventACEValue(ifitsPreͲReporting
ContingencyEventACEValuewasnegative);however,anyBalancing
ContingencyEventthatoccursduringtheContingencyEventRecoveryPeriod
shallreducetherequiredrecovery:(i)beginningatthetimeof,and(ii)bythe
magnitudeof,suchindividualBalancingContingencyEvent.


1.2. documentallReportableBalancingContingencyEventsusingCRForm1.
1.3. deployContingencyReserve,withinsystemconstraints,torespondtoall
ReportableBalancingContingencyEvents,however,itisnotsubjectto
compliancewithRequirementR1part1.1if:
1.3..1 theResponsibleEntityis:
x

isaBalancingAuthorityexperiencingaReliabilityCoordinatordeclared
EnergyEmergencyAlertLevelorisaReserveSharingGroupwhose
member,ormembers,areexperiencingaReliabilityCoordinator
declaredEnergyEmergencyAlertlevel,and

x

isutilizingitsContingencyReservetomitigateanoperatingemergency
inaccordancewithitsemergencyOperatingPlan,and

x

theResponsibleEntityhasdepleteditsContingencyReservetoalevel
belowitsMostSevereSingleContingency

or,
1.3.2 theResponsibleEntityexperiences:
x

multipleContingencieswherethecombinedMWlossexceedsits
MostSevereSingleContingencyandthataredefinedasasingle
BalancingContingencyEvent,or

x

multipleBalancingContingencyEventswithinthesumofthetime
periodsdefinedbytheContingencyEventRecoveryPeriodand
ContingencyReserveRestorationPeriodwhosecombinedmagnitude
exceedstheResponsibleEntity'sMostSevereSingleContingency.

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BackgroundandRationale
RequirementR1reflectstheoperatingprinciplesfirstestablishedbyNERCPolicy1.Its
objectiveistoassuretheResponsibleEntitybalancesresourcesanddemandandreturnsits
ReportableAreaControlError(ACE)todefinedvalues(subjecttoapplicablelimits)followinga
ReportableBalancingContingencyEvent.ItrequirestheResponsibleEntitytorecoverfrom
eventsthatwouldbelessthanorequaltotheResponsibleEntity’sMSSC.Itestablishes
recoveryandrestorationtimeframestheResponsibleEntitymustdemonstrateinacompliance
evaluation.Itisintendedtoeliminatetheambiguitiesandquestionsassociatedwiththe
existingstandard.Inaddition,itallowsResponsibleEntitiestohaveaclearwaytodemonstrate
complianceandsupporttheInterconnectiontothefullextentofitsMSSC.
Byincludingnewdefinitions,andmodifyingexistingdefinitions,andtheaboveR1,thedrafting
teambelievesithassuccessfullyfulfilledtherequirementsofFERCOrderNo.693(atP356)to
includearequirementthatexplicitlyallowsDSMtobeusedasaresourceforContingency
Reserve.Italsorecognizesthatthelossoftransmissionaswellasgenerationmayrequirethe
deploymentofContingencyReserve.
Additionally,R1isdesignedtoassuretheapplicableentityusesreservetocoveraReportable
BalancingContingencyEventorthecombinationofanypreviousBalancingContingencyEvents
thathaveoccurredwithinthespecifiedperiod,toaddresstheOrder’sconcernthatthe
applicableentityisrespondingtoeventsandperformanceismeasured.TheReportable
BalancingContingencyEventdefinition,alongwithR1,allowsformeasurementof
performance.
Inaddition,thestandarddraftingteam(SDT)throughR1Part1.3hasclearlyidentifiedwhenR1
isnotapplicable.ByincludingR1Part1.3.1,theproposedstandardeliminatestheexisting
conflictwiththeEOPStandardsandfurtheraddressestheoutstandinginterpretation.By
clearlystatingwhenR1isnotapplicableordoesnotapply,iteliminatesanyauditor
interpretationandallowstheResponsibleEntitytoperformthefunctioninareliablemanner.
RequirementR1doesnotapplywhenanentityexperiencesaBalancingContingencyEventthat
exceedsitsMSSC(whichincludesmultipleBalancingContingencyEventsasdescribedinR1part
1.3.2)becauseafundamentalgoaloftheSDTistoassuretheResponsibleEntityhasenough
flexibilitytomaintainservicetoloadwhilemanagingreliability.Also,theSDT’sintentisto
eliminateanypotentialoverlaporconflictwithanyotherNERCReliabilityStandardtoeliminate
duplicativereporting,andotherissues.
ThedraftingteamuseddatasuppliedbytheConsortiumforElectricReliabilityTechnology
Solutions(CERTS)tohelpdeterminealleventsthathaveanimpactonfrequency.Datathat
wascompiledbyCERTStoprovideinformationonmeasuredfrequencyeventsispresentedin
Attachment1.Analyzingthedata,revealseventsof100MWorgreaterwouldcaptureall
frequencyeventsforallinterconnections.However,ata100MWreportingthreshold,the
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numberofeventsreportedwouldsignificantlyincreasewithnoreliabilitygainsince100MWis
morereflectiveoftheoutlyingevents,especiallyonlargerinterconnections.
ThegoalofthedraftingteamwastodesignacontinentͲwidestandardtocapturethemajority
oftheeventsthatimpactfrequency.Afterreviewingthedataandindustrycomments,theSDT
electedtoestablishreportingthresholdminimumsforeachrespectiveInterconnection.This
assurestherequirementsofFERCOrderNo.693aremet.Thereportablethresholdwas
selectedasthelesserof80%oftheapplicableentity’sMostSevereSingleContingencyorthe
followingvaluesforeachrespectiveInterconnection:
x
x
x
x

EasternInterconnection–900MW
WesternInterconnection–500MW
ERCOT–800MW
Quebec–500MW

Additionally,thedraftingteamusedonlylossofresourceeventsforpurposesofdetermining
theabovethresholds.
ViolationSeverityLevels
IntheViolationSeverityLevelsforRequirementR1,theimpactoftheResponsibleEntity
recoveringfromaReportableBalancingContingencyEventdependsonthepercentageof
desiredrecoveryachieved.
ComplianceCalculation
ItisimportanttonotethatR1adjuststherequiredrecoveryvalueofReportingACEforany
otherBalancingContingencyEventsthatoccurduringtheContingencyEventRecoveryPeriod.
However,todeterminecompliancescoreforcompliancewithR1,themeasuredcontingency
reserveresponse(insteadoftherequiredrecoveryvalueofReportingACE)isadjustedforany
otherBalancingContingencyEventsthatoccurduringtheContingencyEventRecoveryPeriod.
Bothmethodsofadjustmentaremathematicallyequivalent.Accordingly,themeasured
contingencyreserveresponseiscomputedandcomparedwiththeMWlostasfollows
(assumingallresourcelossvalues,i.e.BalancingContingencyEvents,arepositive)tomeasure
compliance1:
• Themeasuredcontingencyreserveresponseisequaltooneofthefollowing:

1

Inadjustingfortheadverseimpactofrapidlysucceeding(i.e.“near”)EventsonaResponsibleEntity’sRecovery

fromanEvent,theSDTthoughtitmoreprudenttoadjustforfuturenearEventsratherthanforpastnearEvents
becausethefutureEventsplaceanaddedburdenonperformance,whileadjustingforthepastEventsinstead
lowerstheperformancerequirement.ToadjustforbothfutureandpastEventsamountstodoubledealing
becauseanEventissubsequenttoapriornearEvent,andbothEventswouldbeservingtorelieveRecoveryfrom
eachother.TheSDTallowedonlyfortheextremecaseofexemptingfromrecoverypriornearEventsthat
combinedexceedMSSC.

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o IfthePreͲReportableContingencyEventACEValueisgreaterthanorequal
tozero,thenthemeasuredcontingencyreserveresponseequals(a)the
megawattvalueoftheReportableBalancingContingencyEventplus(b)the
mostpositiveACEvaluewithinitsContingencyEventRecoveryPeriod(and
followingtheoccurrenceofthelastsubsequentevent,ifany)plus(c)the
sumofthemegawattlossesofthesubsequentBalancingContingencyEvents
occurringwithintheContingencyEventRecoveryPeriodoftheReportable
BalancingContingencyEvent.
o IfthePreͲReportableContingencyEventACEValueislessthanzero,thenthe
measuredcontingencyreserveresponseequals(a)themegawattvalueof
theReportableBalancingContingencyEventplus(b)themostpositiveACE
valuewithinitsContingencyEventRecoveryPeriod(andfollowingthe
occurrenceofthelastsubsequentevent,ifany)plus(c)thesumofthe
megawattlossesofsubsequentBalancingContingencyEventsoccurring
withintheContingencyEventRecoveryPeriodoftheReportableBalancing
ContingencyEvent,minus(d)thePreͲReportableContingencyEventACE
Value.
• ComplianceiscomputedasfollowsonCRForm1inordertodocumentall
BalancingContingencyEventsusedincompliancedetermination:
ƒ

Ifthemeasuredcontingencyreserveresponseisgreaterthanor
equaltothemegawattslost,thentheReportableBalancing
ContingencyEventComplianceequals100percent.

ƒ

Ifthemeasuredcontingencyreserveresponseislessthanorequalto
zero,thentheReportableBalancingContingencyEventCompliance
equals0percent.

ƒ

Ifthemeasuredcontingencyreserveresponseislessthanthe
megawattslostbutgreaterthanzero,thentheReportableBalancing
ContingencyEventComplianceequals100%*(1–((megawattslost–
measuredcontingencyreserveresponse)/megawattslost)).


Theabovecomputationscanbeexpressedmathematicallyinthefollowing5sequentialsteps,
labeledas[1Ͳ5],where:
ACE_BEST–mostpositiveACEduringtheContingencyEventRecoveryPeriodoccurringafter
thelastsubsequentevent,ifany(MW)
ACE_PREͲPreͲReportableContingencyEventACEValue(MW)
COMPLIANCEͲReportableBalancingContingencyEventCompliancepercentage(0Ͳ100%)
MEAS_CR_RESPͲmeasuredcontingencyreserveresponsefortheReportableBalancing
ContingencyEvent(MW)
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MSSC–MostSevereSingleContingency(MW)
MW_LOSTͲmegawattlossoftheReportableBalancingContingencyEvent(MW)
SUM_SUBSQͲsumofthemegawattlossesofsubsequentBalancingContingencyEvents
occurringwithintheContingencyEventRecoveryPeriodoftheReportableBalancing
ContingencyEvent(MW)

IfACE_PREisgreaterthanorequalto0,then
MEAS_CR_RESP=MW_LOST+ACE_BEST+SUM_SUBSQ[1]

IfACE_PREislessthan0,then
MEAS_CR_RESP=MW_LOST+ACE_BEST+SUM_SUBSQ–ACE_PRE[2]

IfMEAS_CR_RESPisgreaterthanorequaltoMW_LOST,then
COMPLIANCE=100[3]

IfMEAS_CR_RESPislessthanorequalto0,then
COMPLIANCE=0[4]

IfMEAS_CR_RESPisgreaterthan0,and,MEAS_CR_RESPislessthanMW_LOST,then
COMPLIANCE=100*(1–((MW_LOST–MEAS_CR_RESP)/MW_LOST))[5]


TheDecisionTreeflowdiagramforDCSbelow,providesavisualizationofthelogicflowfora
ReportableBalancingContingencyEvent.Itincludesdecisionblocksforinitialevent
determination,subsequenteventdetermination,andcheckingforMSSCexceedance which
shouldassisttheResponsibleEntitywithEventRecoveryandanalysis.


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BAAL and
IROL

Resource Loss
> Reporting
Threshold

DCS Real
Time


DCS Off
Line
Reporting

N

Sudden?

Y

Start 15
Minute
Recovery



Subsequent
Events?

Y



N

DecisionTreeforDCS

Make Best
Efforts on
Recovery

> MSSC

Adjust
Calculations

Y

13

N

If IROL or
BAAL
Exceeded, Begin
30 Min Recover

Complete
Form

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Document

DisturbanceControlPerformanceͲContingencyReserveforRecoveryFromaBalancing
ContingencyEventStandardBackgroundDocument

Requirement2
R2.

EachResponsibleEntityshalldevelop,reviewandmaintainannually,andimplement
anOperatingProcessaspartofitsOperatingPlantodetermineitsMostSevere
SingleContingencyandmakepreparationstohaveContingencyReserveequalto,or
greaterthantheResponsibleEntity’sMostSevereSingleContingencyavailablefor
maintainingsystemreliability.

BackgroundandRationale
R2establishesauniformcontinentͲwidecontingencyreservepolicyintheformofa
requirementthataResponsibleEntityimplementanOperatingPlanthatassuresContingency
Reservebeatleastequaltotheapplicableentity’sMostSevereSingleContingencyanda
definitionofMostSevereSingleContingency.ItsgoalistoassurethattheResponsibleEntity
willhavesufficientContingencyReservethatcanbedeployedtomeetR1.
FERCOrder693(atP356)directedBALͲ002tobedevelopedasacontinentͲwidecontingency
reservepolicy.R2fulfillstherequirementassociatedwiththerequiredamountofcontingency
reserveaResponsibleEntitymusthaveavailabletorespondtoaReportableBalancing
ContingencyEvent.WithinFERCOrder693(atP336)theCommissionnotedthatthe
appropriatemixofoperatingreserve,spinningreserveandnonͲspinningreserveshouldbe
addressed.However,theOrderpredatedtheapprovalofthenewBALͲ003,whichaddresses
frequencyresponsivereserveandtheamountoffrequencyresponseobligation.Withthe
developmentofBALͲ003,andtheassociatedreliabilityperformancerequirement,theSDT
believesthat,withR2ofBALͲ002andtheapprovalofBALͲ003,theCommission’sgoalsofa
continentͲwidecontingencyreservespolicyismet.ThesuitesofBALstandards(BALͲ001,BALͲ
002,andBALͲ003)areallperformanceͲbased.Withthesuiteofstandardsandthespecific
requirementswithineachrespectivestandard,acontinentͲwidecontingencypolicyis
established.
TheResponsibleEntity’sOperatingPlanwilladdresstheprocessbywhichContingency
ReservesgreaterthanorequaltotheMostSevereSingleContingencyareavailableinRealͲ
time.Onceanentityutilizesitscontingencyreserve,RequirementR3addressesrestorationof
thereserves.


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Requirement3
R3.

EachResponsibleEntity,followingaReportableBalancingContingencyEvent,shall
restoreitsContingencyReservetoatleastitsMostSevereSingleContingency,
beforetheendoftheContingencyReserveRestorationPeriod,butanyBalancing
ContingencyEventthatoccursbeforetheendofaContingencyReserveRestoration
periodresetsthebeginningoftheContingencyEventRecoveryPeriod.


BackgroundandRationale
RequirementR3establishestherestorationofContingencyReservesfollowingReportable
BalancingContingencyEvents.Thisrequirementaddressestheneedtobepreparedforfuture
BalancingContingencyEvents.ContingencyReservesmustberestoredtoatleasttheminimum
requiredamount,theMostSevereSingleContingency,toassurethatthenexteventforwhich
anentityplansisexpectedtobecoverediftheeventoccurs.ContingencyReservesmustbe
restoredwithintheContingencyReserveRestorationPeriodwhichisdefinedasaperiodnot
exceeding90minutesfollowingtheendoftheContingencyEventRecoveryPeriod,whichis15
minutes.






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Attachment 1
NERC Interconnections 2009-2013
Frequency Events Loss MW Statistics

For: NERC BARC Standard Drafting Team
Prepared by: CERTS
Date: October 15, 2013

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ContingencyEventStandardBackgroundDocument

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ContingencyEventStandardBackgroundDocument

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Attachment 2
Technical Justification for Applicability
of BAL-002 During Emergency Alerts

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TechnicalJustificationforApplicabilityofBALͲ002
DuringEnergyEmergencyAlerts

I.

INTRODUCTION


TheBalancingAuthorityReliabilityͲbasedControlsstandarddraftingteam(BARCSDT)has
identifiedaconflictbetweenNERCReliabilityStandardsBALͲ002andEOPͲ002that
unnecessarilyrequiresarbitraryinterruptionofFirmLoad.Inordertoaddressthisissue,the
BARCSDTisrecommendingthatStandardBALͲ002Ͳ2notbeenforceableduringanEnergy
EmergencyAlert(EEA)eventwheretheEEAprocessrequirestheuseofContingencyReserveto
maintainloadservice.2Thisdocumentprovidessupportforthisrecommendationandan
overviewofreliablefrequencymanagementontheNorthAmericanInterconnections.

II.
BACKGROUND

ReliablybalancinganInterconnectionrequiresfrequencymanagementandallofitsaspects.
InputstofrequencymanagementincludeTieͲLineBiasControl,AreaControlError(ACE),and
thevariousRequirementsinNERCResourceandDemandBalancingStandards,specificallyBALͲ
001Ͳ2RealPowerBalancingControlPerformanceandBALͲ003Ͳ1FrequencyResponseand
FrequencyBiasSetting.

ReliabilityStandardBALͲ002appliesduringtherealͲtimeoperationstimehorizonand
addressesthebalancingofresourcesanddemandfollowingadisturbance.ReliabilityStandard
EOPͲ002alsoappliesduringtherealͲtimeoperationstimehorizonandaddressescapacityand
energyemergencies.Giventhatanentityand/oreventcantransitionsuddenlyfromnormal
operationsintoemergencyoperations(EOPͲ002)whereContingencyReservemaintainedunder
BALͲ002maybeutilizedtoserveFirmLoad,thistransitionalseammustbeexplicitlyaddressed
inordertoprovideclaritytoresponsibleentitiesregardingtheactionstobetaken.The
proposedapplicabilityofBALͲ002isdesignedtoaddressthisissue.

III.
LEGACYREQUIREMENTS

TheResourceandDemandBalancing(BAL)standardsincludebothrequirementsthathavea
soundtechnicalbasisandlegacyrequirementsthattheindustryhasusedforyearsbutfailto

2

Theproposedapplicabilitysectionstates:“ApplicabilityisdeterminedonanindividualReportableBalancing
ContingencyEventbasis,buttheResponsibleEntityisnotsubjecttocomplianceduringperiodswhenthe
ResponsibleEntityisinanEnergyEmergencyAlertLevelunderwhichContingencyReserveshavebeenactivated.”
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haveasoundtechnicalbasis.NERCbeganreplacingtheselegacyrequirementswithtechnically
basedrequirementsstartingwiththeControlPerformanceStandard1(CPS1).BothControl
PerformanceStandard2(CPS2)andtheDisturbanceControlStandard(DCS)remaininthe
legacycategory.Thefollowingarespecificconcernsassociatedwiththeserequirements.
o WhenCPS1wasimplementedtoreplaceA1/A2,previousrequirementswere
modifiedsothatCPS1wouldapplyatalltimesincludingthe(disturbance)
periodswhereDCSisapplicable,notjustduringnormaloperations/periods.So
DCSisnottheonlystandardgoverningdisturbanceconditions.
o TheDisturbanceControlStandard(DCS)anditsprecursorB1/B2havebeen
uniqueinrequiringimmediateactionbytheBalancingAuthority(BA),inthis
casetoaddressunexpectedimbalanceswithindefinedlimits.
o DCS,albeitresultsͲbasedinitscurrentform,wasinitiallydesignedtomeasure
theutilizationofContingencyReservetoaddressalossofresourcewithinthe
definedlimits.InitsresultsͲbasedformitassumedthatimplementingsufficient
ContingencyReservesasneededtocomplywiththerecoveryrequirement
wouldbeareasonablyequitableminimumquantityforallBAsparticipatingin
interconnectedoperation.
o DCSisbaseduponACErecoverytothelowerofpreͲdisturbanceACEorzero.A
BalancingAuthoritywhichmightbeunderͲgeneratingpriortoagenerationloss,
couldloseageneratingunitandunderDCSbedeemedcompliantifitreturned
ACEtoitspreͲdisturbancestate,thoughitcouldstillbedepressing
Interconnectionfrequency.
o AsDCSrecoveryfromareportableeventmustoccurwithina15Ͳminuteperiod,
itispossibleforaBalancingAuthority’sACEtoagaingonegativeafterthattime,
withasimilarimpactonInterconnectionfrequency.
o SinceCPS2allowsaBAtobeunaccountableforapproximately74hoursof
operationina31Ͳdaymonth,animbalanceconditionmaypersistandnegatively
impactInterconnectionfrequencyformanyhours3.
o WhenACEismodulatedbyfrequency,“significant”lossesaredefinednotonly
bythesizeoftheeventcausinganACEdeviation,butalsocontingentonthe
deviationofInterconnectionfrequencyfromScheduledFrequency.

IV.
TIEͲLINEBIASFREQUENCYCONTROLANDACE


3

ReliabilityͲBasedControlv3,StandardAuthorizationRequestForm,November7,2007.

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TieͲLineBiasFrequencyControlisimplementedontheNorthAmericanInterconnections
throughtheuseoftheACEEquation.4Ingeneral,ACEisthetermusedtodeterminetheloadͲ
generationimbalancethatisbeingcontributedbyeachBalancingAuthority(BA)onan
Interconnection.ACEisapowerfulindicator,becauseitindicatestheimbalancewithinthe
boundariesofasingleBA,thusdefiningtheSecondaryControlresponsibilitiesforthatBAand,
therefore,thecontrolactionthatwouldreturnACEtozero.ACEincludestheFrequencyBias
Settingterm,whichallowsthePrimaryFrequencyControltobeasharedservicethroughouta
multiͲBAInterconnection,whileassigningtoeachindividualBAthespecificresponsibilitiesof
maintainingitsownSecondaryFrequencyControl.

Insummary,ACEonlyprovidesguidancewithrespecttoSecondaryFrequencyControland
doesnotindicateorprovideanydirectmeasureofPrimaryFrequencyControl,andonlyreflects
theestimatedFrequencyResponseasrepresentedbytheFrequencyBiasSettingterm.NERC
RequirementsandsupportingdocumentationforFrequencyResponse(PrimaryFrequency
Control)areincludedinBALͲ003Ͳ1FrequencyResponseandFrequencyBiasSettingstandard.
MoredetailonTieͲLineBiasFrequencyControlandACEisattached.5

V.
CONTROLPERFORMANCESTANDARD1(CPS1)

PriortothedevelopmentofCPS1,theindustryassumedthat,"Itisimpossible,however,to
usefrequencydeviationtoidentifythespecificcontrolarea(sic,i.e.BA)withtheunderͲor
overͲgenerationcreatingthefrequencydeviation…".3Inthe1990'sthedevelopmentofCPS1
demonstratedthatnotonlywasitpossibletoidentifythespecificBAcreatingthefrequency
deviation,butthatitisalsopossiblenotonlytodeterminetherelativecontributionbyeachBA
tothemagnitudeofthefrequencydeviation6,butalsotodeterminetherelativecontributionof
eachBAtothereliabilityriskcausedbythatdeviation.Inaddition,theCPS1Requirement
providedaguarantee:"IfallBAsonaninterconnectioncompliedwiththeCPS1Requirement,

4

Illian,HowardF.,UnderstandingACE,CPS1andBAAL,PreparedfortheNERCBARCStandardDraftingTeam,
September10,2010rev.August19,2014,Section2,pp.1Ͳ4,foraderivationoftheACEEquationandthe
requirementsforimplementingitthatareincludedinthedefinitionofACEappearingintheNERCGlossary.

5

Illian, Howard F., Frequency Control Performance Measurement and Requirements, Ernest
Orlando Lawrence Berkeley National Laboratory, December 2010, for a discussion of the
history of Frequency Control and Performance Measurement.

6

Illian, Howard F., Understanding ACE, CPS1 and BAAL, Section 2, pp. 5-10 for a derivation
of the CPS1 requirement.

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theRootMeanSquared7valueofthefrequencydeviationforthatInterconnectionwouldbe
lessthantheepsilon18frequencydeviationlimitforthatInterconnection."

CPS1isarollingannualaverageofindividualmeasurementseachaveragedoveroneͲ
minute,andisassessedmonthly.CPS1measuresthecovariancebetweentheACEofaBAand
thefrequencydeviationoftheInterconnectionwhichisequaltothesumoftheACEsofallof
theBAs.CPS1hasthegreatvalueofusingtheInterconnectionfrequencytodeterminethe
degreetowhichACEamongtheBAsonamultipleBAInterconnectionisharmingorhelping
interconnectionfrequency.Sincethefrequencydeviationisameasuredvalue,theACEofaBA
willdirectlyaffectonlytheCPS1oftheBAwiththeACEandnottheCPS1measureofotherBAs.

VI.
BALANCINGAUTHORITYACELIMIT(BAAL)

WhentheBalancingResourcesandDemand(BRD)standarddraftingteamrecognizedthe
needforacontrolmeasureoverashortertimehorizonthaneitherCPS1(annual)orControl
PerformanceStandard29(CPS2,monthly)provided,itbeganlookingforameasurethatwould
allowawindowforcommonimbalanceeventslikeaunittrip,whileprovidingalimitonhow
muchfrequencydeviationshouldbeallowedoverthatshortperiod.Afterconsidering
numerousalternatives,BAALwasselectedastheappropriateshortͲtermmeasure.10,11


7

“Root Mean Squared” means the square root of the mean of the squared errors, so that
positive and negative errors do not offset each other and any shift in the mean is counted
as error.

8

“Epsilon1” is the frequency deviation limit determined for each North American
Interconnection and used by CPS1 to bound the Root Mean Squared frequency deviation.
It is 18 mHz on the Eastern, 22.8 mHz on the Western, 30 mHz on the ERCOT, and 21
mHz on the Quebec Interconnections.

9

Proposed to be replaced by BAAL under BAL-001-2, CPS2 requires the BA to move its ACE
within predefined L10 bounds when it is binding (during only 90% of the ten-minute
periods per month) without regard to whether such action helps or hurts Interconnection
frequency.

10

Illian, Howard F., Meeting the Discrete Event Measure (DEM) Objectives with the
Abnormal Operations Measure (AOM), Prepared for the NERC Balancing Resources and
Demand Standard Drafting Team, March 20, 2004.

11

Illian, Howard F., Setting the Balancing Authority ACE Limit (BAAL) for the NERC
Abnormal Operations Measure (AOM), Prepared for the NERC Balancing Resources and
Demand Standard Drafting Team, March 28, 2004.

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ConsiderableevaluationandFieldTrialshaveshownthatBAAL12isabetterindicatorof
contributionstoreliabilityriskofaninterconnectionthanthemagnitudeofACEalone.This
superiority,likeCPS1’s,derivesfromtheconcurrentuseofbothACEandfrequencyerrorinthe
BAALmeasure.ThusBAALcapturestherelativecontributiontoreliabilitybyalloftheACEson
aninterconnectionandindicateswhereeachBAstandsrelativetoitssecondarycontrol
responsibilitiesandthecurrentstateoftheinterconnectionasindicatedbythefrequencyerror
forbothunderͲandoverͲfrequencyconditions.

VII.
INTERACTIONBETWEENSTANDARDS

Thedraftingteamhasidentifiedasanissuetheexistenceofpointswherethestandardsare
inconflictwitheachother.Thedraftingteamhasattemptedtoaddresstheconflictsidentified,
asfollows:

NERCstandardEOPͲ002requiresaBAtouseallitsreservesduringanEnergyEmergency
Alert2(EEA2)orhigher.ThefollowinglanguageisfoundinEOPͲ002Attachment1ͲEOPͲ002:
2.6.4OperatingReserves.Operatingreservesarebeingutilizedsuchthatthe
EnergyDeficientEntityiscarryingreservesbelowtherequiredminimumor
hasinitiatedemergencyassistancethroughitsoperatingreservesharing
program.

ThecurrentBALͲ002specifiesaminimumlevelreserverequirementatalltimesunlessa
qualifyingeventhasoccurred.ThedraftingteamnotedthatintheEEAprocessanentityis
driventorequestanEEArarelyastheresultofasingleunitloss.Infact,anEEAdeclarationby
theReliabilityCoordinatormightresultfromissuesthatincludenoeventthatwouldqualifyas
aDisturbanceandtheEEAsituationcouldlastlongerthanthereserverecoveryperiodof90
minutes.Forthisreason,thedraftingteamrecommendssignificantchangestothestandardsin
question.

Inadditiontotheidentifiedconflict,otherstandardscanrequiretheactivationof
contingencyreserve.TheseincludeotherBALstandards,IROstandardsandTOPstandards.
Comparedtothosestandards,theBALͲ002standardprovidestheleastdirectmeasureof
reliability.Therefore,anentityshouldneverbeconflictedbetweenapplyingtherequirements
ofBALͲ002andcomplyingwiththeotherstandards.


12

Illian, Howard F., Understanding ACE, CPS1 and BAAL, Prepared for the NERC BARC
Standard Drafting Team, September 10, 2010 rev. August 19, 2014, Section 2, pp. 10, for
a derivation of the BAAL requirement.

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Finally,thereisoneoverarchingprincipalnotreflectedinthediscussionuptothispoint,
namelykeepingthelightsonifpossible.IfthereisarequirementtobringACEbacknomatter
what,thenthatrequirementwillhavetheunintendedconsequenceofsheddingFirmLoad,
especiallyduringanEEA.DuringtheEEAprocess,theexpectationisthataBAwillhavefirm
loadreadytoshedinordertomeetitsreserverequirementunderR2oftheproposedBALͲ002
standard.However,iftheBALͲ002standardalsorequirestheentitytomeetR1duringtheEEA,
entitieswillshedfirmloadtorestoreACEtoitspreͲcontingencylevel,regardlessofthelackof
anyreliabilityissues.Inotherwords,frequencycouldbesettlingatorverynear60Hz,no
transmissionlinesareoverloadedasdeterminedbytheTOPstandards,andtheentityis
operatingwithintheparametersdefinedinBALͲ001,butfirmloadwouldbeinterruptedsimply
tobringtheentity’sACEbacktowhatitwaspriortothelossoftheunit.Sincetheindustryhas
definedreliabilityasfrequencyatornear60Hzandtransmissionlinesoperatingwithintheir
limits,thereisnoreasontointerruptfirmload.

Instead,theBARCSDTisrecommendingthatStandardBALͲ002Ͳ2notbeenforceable
duringanEEAeventwheretheEEAprocessrequirestheuseofContingencyReserveto
maintainloadservice.Instead,theReliabilityCoordinator,TransmissionOperatorsandthe
impactedBalancingAuthoritiesshoulduserealͲtimesituationalawareness,takingintoaccount
issuesaddressedinBALͲ001,BALͲ003,theIROsuiteofstandardsandtheTOPsuiteof
standards,todeterminewhatactionsareappropriatewhenconditionsareabnormal.This
processwouldallowcontinuedloadservicewithoutarbitrarilyrequiringinterruptionoffirm
load.

Thisconcernarisesbecausetheotherstandardslookatspecificreliabilityissuesother
thanjustbalancingbetweenscheduledandactualinterchange.BALͲ001Ͳ2andBALͲ003Ͳ1look
atinterconnectionfrequencytodeterminewhethertheBalancingAuthorityishelpingor
hurtingreliability.DuringanEEAevent,curtailingloadtomoveACEbacktoapreͲeventlevel
couldadverselyaffectfrequency.Iffrequencygoesupfrom60HzwhenaBalancingAuthority
interruptsload,theimpactisdetrimentaltotheinterconnection.UndertheTOPstandards,if
flowsontransmissionlinesarewithinthelimitsspecified,thereisnoneedtoaltertheflowson
thetransmissionsystembyinterruptingload.

Finally,theReliabilityCoordinatorhasawideareaviewoftheelectricsystemas
requiredundertheIROstandards.TheIROstandardsclearlystatetheReliabilityCoordinator’s
responsibilitiesduringtheEEAprocess.IftheReliabilityCoordinatorhasnotidentifieda
reliabilityconcerninitsneartermoperationsevaluation,actionssuchasinterruptionoffirm
loadshouldnotoccursimplytobalanceloadandresourceswithintheBA.Duringabnormal
(emergency)situations,takingsignificantactionswithanarrowviewwillnotbebeneficialfor
Interconnectionreliability.

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EXAMPLES
o Example1
OnanusuallycolddayinFebruary2011,at06:22,aBalancingAuthorityArea
(BAA)experienceda350MWgenerationlosswhena750MWjointownership
unittrippedoffͲline.EarlierinthedaytheBAAoperatorexperiencedlossof
severalgeneratingunitswithatotalcapacityof1050MW,thelatestlossbeing
just38minutespriortothe350MWloss.Whenthe350MWeventoccurred
theBAAoperatorrequestedreserve/emergencyassistance,shed300MWof
customerloadtorestorecontingencyreserve,andrequestedtheRCpostan
EEA3.TheEEA3wasposted.Althoughthefrequencyonlytouched59.91Hz,
averaging59.951Hzinthefirstminuteoftheoutage,wasitreallynecessaryto
cutloadandleavepeopleinthecold,darkofthatmorningtorestore
contingencyreserve?Havingidlegeneration,whentheInterconnectionis
operatingreliably,doesnotwarrantsheddingcustomerload.
o Example2
InJune2012,at17:08,aBAAexperiencedan800MWgenerationloss.TheBA
andthereservesharinggroup(RSG)itparticipatesinwereintheprocessof
replacingthelostgenerationwhen,inthethirteenthminuteoftherecovery
whentherewerenoidentifiedfrequency,voltageorloadingthreatstoreliability,
theBAAwasdirectedbyitsReliabilityCoordinator(RC)toshed120MWof
customerload.AlthoughthecombinedAreaControlError(ACE)oftheRSG
participantswaspositive,theRCfocusedontheACEoftheBAAthatlostthe
generation–whichwasstillnegative–ignoringthefactthattheInterconnection
frequency(59.96Hz)wasabovetheFrequencyTriggerLimit(59.932Hz).The
needlesssheddingofcustomerloadwhensystemreliabilityisnotthreatened
attractedtheattentionofstateregulatorswhowerenothappywiththeaction.
ThisdemonstratesthatfocusingsolelyonaBAA’sACEandnotonthetrue
Interconnectionreliabilityindicatorscancauseactionsthatdonotsupport
reliability.
o Example3
InJune2004,at0741,aseriesofeventsledtoagenerationlossofover4,600
MW.Inspiteoftheeventsize,theInterconnectionfrequencywasarrested
withouttriggeringautomaticunderfrequencyloadshedding,thankstogovernor
action,frequencysensitiveloadanddeploymentofContingencyReserve(as
requiredbyBALͲ002).Sometransmissionelementsexceededtheirlimitsfora
shorttime(aspermittedbytheEOPstandards),And,priortothedisturbance,
thefrequencywasinthenormaloperatingrangeduetoautomaticgeneration
control(AGC)operation(asrequiredbyBALͲ001).Duringtheeventalmost1,000
MWofinterruptiblecustomerloadwasshedthroughouttheinterconnected
systemsbydevicesthatautomaticallyoperatedtoprotectvariouspartsofthe
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system(asdeterminedbytheTPLandTOPStandards).Thisdemonstrateshow
thesuiteofstandardsdefinedbyNERCworktogethertoefficientlyprotectthe
systemandminimizecustomerinterruptions.

CONCLUSIONS

VIII.

Thereareimportantconclusionsthatcanbedrawnfromthisworkandthe
mathematicalguaranteesthatitprovides:

o TheDisturbanceControlStandard(DCS)ascurrentlyconfiguredonlylooksat
ACE,theimbalancecontributionofasingleBA,anddoesnotincludeaspecific
frequencyerrorcomponentthatindicatestheBA’scontributionrelativetothe
conditionoftheinterconnectiontowhichtheBAisconnected.

o AstheDCSmeasuredoesnothaveaspecificfrequencycomponent,compliance
toDCSattimesconflictswiththeoverallgoaloftargetingoperationwithin
predefinedInterconnectionfrequencylimits.Forexample,DCSrecoveryinitiated
fromaboveScheduledFrequencyhasadetrimentalimpactonInterconnection
frequency.

o ThefocusonACEaloneisinsufficienttocontrolfrequencyonamultipleBA
Interconnection.ThecorrelationoftheACEsamongtheBAsonthe
Interconnectionwillaffectthequalityoffrequencycontrolindependentofhow
anyindividualACEiscontrolled.

o AdequatecontrolofInterconnectionfrequencyrequirestheuseofbothACE
(individualBAbalancingerror)andfrequencydeviation.

o AdequatecontrolofreliabilityriskonanInterconnectionrequirestheuseof
ACE,frequencydeviationandavailablefrequencyresponse.

o BAALaddressesalleventsimpactingInterconnectionfrequency,bothaboveand
belowscheduledfrequency.

BAALaddressesalloftheaboveissuesinitstimedomainwithoutrequiringresponsetoor
measurementofeventsthatfailtoraisereliabilityconcerns.Forthesereasons,theproposed
applicabilityofBALͲ002isareasonableandtechnicallyͲjustifiedapproachthataddressesthe
seamwithEOPͲ002.

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Violation Risk Factor and Violation Severity
Level Assignments

Project 2010-14.1 Balancing Authority Reliability-based Controls
- Reserves
Thisdocumentprovidesthedraftingteam’sjustificationforassignmentofviolationriskfactors(VRFs)
andviolationseveritylevels(VSLs)foreachrequirementinBALͲ002Ͳ2,ContingencyReservefor
RecoveryfromaBalancingContingencyEvent.EachprimaryrequirementisassignedaVRFandasetof
oneormoreVSLs.Theseelementssupportthedeterminationofaninitialvaluerangeforthebase
penaltyamountregardingviolationsofrequirementsinFERCͲapprovedreliabilitystandards,asdefined
intheEROSanctionGuidelines.
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
BALͲ002Ͳ2
VRFandVSLAssignments–July,
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.

BALͲ002Ͳ2
VRFandVSLAssignments–July,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 BAL-002-2:

TherearetworequirementsinBALͲ002Ͳ2.Bothrequirementswereassigneda“Medium”VRF.
VRF for BAL-002-2, Requirement R1:


•

FERCGuideline2—Consistencywithinareliabilitystandardexists.Therequirementdoesnot
containsubͲrequirements.AlloftherequirementsinBALͲ002Ͳ2areassigneda“Medium”VRF.
RequirementR1issimilarinscopetoRequirementR2.Thisisalsoconsistentwithother
reliabilitystandards(i.e.,BALͲ001Ͳ2,BALͲ003Ͳ1,etc).

•

FERCGuideline3—Consistencyamongreliabilitystandardsexists.Thisrequirementissimilar
inconcepttothecurrentenforceableBALͲ001Ͳ0.1aStandardRequirementsR1andR2,which
haveanapprovedMediumVRFandapprovedreliabilitystandardsBALͲ001Ͳ1andBALͲ003Ͳ1.

•

FERCGuideline4—ConsistencywithNERC’sDefinitionoftheVRFlevelselectedexists.This
requirement,ifviolated,coulddirectlyaffecttheelectricalstateorthecapabilityoftheBulk
ElectricSystem,ortheabilitytoeffectivelymonitorandcontroltheBulkElectricSystem,but

BALͲ002Ͳ2
VRFandVSLAssignments–July,2015

3

violation,initself,wouldunlikelyresultintheBulkElectricSysteminstability,separation,or
cascadingfailuressincethisrequirementisanafterͲtheͲfactcalculation,notperformedinRealͲ
time.
•

FERCGuideline5—ThisrequirementdoesnotcoͲminglereliabilityobjectives.

VRF for BAL-002-2, Requirement R2:


•

FERCGuideline2—Consistencywithinareliabilitystandardexists.Therequirementdoesnot
containsubrequirements.AlloftherequirementsinBALͲ002Ͳ2areassigneda“Medium”VRF.
RequirementR2issimilarinscopetoRequirementR1.Thisisalsoconsistentwithother
reliabilitystandards(i.e.,BALͲ001Ͳ2,BALͲ003Ͳ1,etc).

•

FERCGuideline3—ConsistencyamongReliabilityStandardsexists.Thisrequirementissimilar
inconcepttothecurrentenforceableBALͲ001Ͳ0.1astandardRequirementsR1andR2,which
haveanapprovedMediumVRFandapprovedreliabilitystandardsBALͲ001Ͳ1andBALͲ003Ͳ1.

•

FERCGuideline4—ConsistencywithNERC’sDefinitionoftheVRFlevelselectedexists.This
requirement,ifviolated,coulddirectlyaffecttheelectricalstateorthecapabilityoftheBulk
ElectricSystem,ortheabilitytoeffectivelymonitorandcontroltheBulkElectricSystem,but
violation,initself,wouldunlikelyresultintheBulkElectricSysteminstability,separation,or
cascadingfailuressincethisrequirementisanafterͲtheͲfactcalculation,notperformedinRealͲ
time.

•

FERCGuideline5—ThisrequirementdoesnotcoͲminglereliabilityobjectives.


VRF for BAL-002-2, Requirement R3:


•

FERCGuideline2—Consistencywithinareliabilitystandardexists.Therequirementdoesnot
containsubrequirements.AlloftherequirementsinBALͲ002Ͳ2areassigneda“Medium”VRF..
Thisisalsoconsistentwithotherreliabilitystandards(i.e.,BALͲ001Ͳ2,BALͲ003Ͳ1,etc).

•

FERCGuideline3—ConsistencyamongReliabilityStandardsexists.Thisrequirementissimilar
inconcepttothecurrentenforceableBALͲ001Ͳ0.1astandardRequirementsR1andR2,which
haveanapprovedMediumVRF,andapprovedreliabilitystandardsBALͲ001Ͳ1andBALͲ003Ͳ1.

•

FERCGuideline4—ConsistencywithNERC’sDefinitionoftheVRFlevelselectedexists.This
requirement,ifviolated,coulddirectlyaffecttheelectricalstateorthecapabilityoftheBulk
ElectricSystem,ortheabilitytoeffectivelymonitorandcontroltheBulkElectricSystem,but
violation,initself,wouldunlikelyresultintheBulkElectricSysteminstability,separation,or

BALͲ002Ͳ2
VRFandVSLAssignments–July,2015

4

cascadingfailuressincethisrequirementisanafterͲtheͲfactcalculation,notperformedinRealͲ
time.
•

FERCGuideline5—ThisrequirementdoesnotcoͲminglereliabilityobjectives.



BALͲ002Ͳ2
VRFandVSLAssignments–July,2015

5

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
eachrequirementinBALͲ002Ͳ2meettheFERCGuidelinesforassessingVSLs:

BALͲ002Ͳ2
VRFandVSLAssignments–July,2015

6

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.

BALͲ002Ͳ2
VRFandVSLAssignments–July,2015

7

TheNERCVSL
Guidelinesare
satisfiedby
incorporating
percentageof
noncompliance
performancefor
thecalculated
CPS1.

BALͲ002Ͳ2
VRFandVSLAssignments–July,
2015


R1

R#

Compliance with
NERC VSL
Guidelines

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

ProposedVSLsarenotbinary.
ProposedVSLlanguagedoesnot
includeambiguoustermsand
ensuresuniformityand
consistencyinthe
determinationofpenalties
basedonlyonthepercentageof
intervalstheentityis
noncompliant.

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

VSLs for BAL-002-2 Requirement R1:


ProposedVSLsdonot
expandonwhatis
requiredinthe
requirement.TheVSLs
assignedonlyconsider
resultsofthecalculation
required.ProposedVSLs
areconsistentwiththe
requirement.

Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement

Guideline 3

8


ProposedVSLsare
basedonsingle
violationsandnota
cumulativeviolation
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.

Thisisanewrequirement.
Asdrafted,theproposed
VSLsdonotlowerthe
currentlevelofcompliance.

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

BALͲ002Ͳ2
VRFandVSLAssignments–July,
2015


R2.

R#

Compliance with
NERC VSL
Guidelines

VSLs for BAL-002-2 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

9


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.

Thisissimilartothecurrent
BALͲ002Ͳ1Requirement
R3.1.Asdrafted,the
proposedVSLsdonotlower
thecurrentlevelof
compliance.

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
contingencyreserve
recovered.

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

BALͲ002Ͳ2
VRFandVSLAssignments–July,2015

R3.

R#

Compliance with
NERC VSL
Guidelines

VSLs for BAL-002-2 Requirement R3:


10

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 2010-14.1 Balancing Authority Reliability-based Controls
- Reserves
Thisdocumentprovidesthedraftingteam’sjustificationforassignmentofviolationriskfactors(VRFs)
andviolationseveritylevels(VSLs)foreachrequirementinBALͲ002Ͳ2,ContingencyReservefor
RecoveryfromaBalancingContingencyEvent.EachprimaryrequirementisassignedaVRFandasetof
oneormoreVSLs.Theseelementssupportthedeterminationofaninitialvaluerangeforthebase
penaltyamountregardingviolationsofrequirementsinFERCͲapprovedreliabilitystandards,asdefined
intheEROSanctionGuidelines.
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
BALͲ002Ͳ2
VRFandVSLAssignments–July,
2013

July,
2015

1



unlikely,underemergency,abnormal,orrestorationconditionsanticipatedbythepreparationstolead
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.

BALͲ002Ͳ2
VRFandVSLAssignments–July,2013July,2015

6
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 BAL-002-2:

TherearetworequirementsinBALͲ002Ͳ2.Bothrequirementswereassigneda“Medium”VRF.
VRF for BAL-002-2, Requirement R1:


•

FERCGuideline2—Consistencywithinareliabilitystandardexists.Therequirementdoesnot
containsubͲrequirements.BothAlloftherequirementsinBALͲ002Ͳ2areassigneda“Medium”
VRF.RequirementR1issimilarinscopetoRequirementR2.Thisisalsoconsistentwithother
reliabilitystandards(i.e.,BALͲ001Ͳ2,BALͲ003Ͳ1,etc).

•

FERCGuideline3—Consistencyamongreliabilitystandardsexists.Thisrequirementissimilar
inconcepttothecurrentenforceableBALͲ001Ͳ0.1aStandardRequirementsR1andR2,which
haveanapprovedMediumVRF,proposedandapprovedreliabilitystandardsBALͲ001Ͳ1and
BALͲ003Ͳ1.

•

FERCGuideline4—ConsistencywithNERC’sDefinitionoftheVRFlevelselectedexists.This
requirement,ifviolated,coulddirectlyaffecttheelectricalstateorthecapabilityoftheBulk

BALͲ002Ͳ2
VRFandVSLAssignments–July,2013July,2015

6
3

ElectricSystem,ortheabilitytoeffectivelymonitorandcontroltheBulkElectricSystem,but
violation,initself,wouldunlikelyresultintheBulkElectricSysteminstability,separation,or
cascadingfailuressincethisrequirementisanafterͲtheͲfactcalculation,notperformedinRealͲ
time.
•

FERCGuideline5—ThisrequirementdoesnotcoͲminglereliabilityobjectives.

VRF for BAL-002-2, Requirement R2:


•

FERCGuideline2—Consistencywithinareliabilitystandardexists.Therequirementdoesnot
containsubrequirements.BothAlloftherequirementsinBALͲ002Ͳ2areassigneda“Medium”
VRF.RequirementR2issimilarinscopetoRequirementR1.Thisisalsoconsistentwithother
reliabilitystandards(i.e.,BALͲ001Ͳ2,BALͲ003Ͳ1,etc).

•

FERCGuideline3—ConsistencyamongReliabilityStandardsexists.Thisrequirementissimilar
inconcepttothecurrentenforceableBALͲ001Ͳ0.1astandardRequirementsR1andR2,which
haveanapprovedMediumVRF,proposedandapprovedreliabilitystandardsBALͲ001Ͳ1and
BALͲ003Ͳ1.

•

FERCGuideline4—ConsistencywithNERC’sDefinitionoftheVRFlevelselectedexists.This
requirement,ifviolated,coulddirectlyaffecttheelectricalstateorthecapabilityoftheBulk
ElectricSystem,ortheabilitytoeffectivelymonitorandcontroltheBulkElectricSystem,but
violation,initself,wouldunlikelyresultintheBulkElectricSysteminstability,separation,or
cascadingfailuressincethisrequirementisanafterͲtheͲfactcalculation,notperformedinRealͲ
time.

•

FERCGuideline5—ThisrequirementdoesnotcoͲminglereliabilityobjectives.


VRF for BAL-002-2, Requirement R3:


•

FERCGuideline2—Consistencywithinareliabilitystandardexists.Therequirementdoesnot
containsubrequirements.AlloftherequirementsinBALͲ002Ͳ2areassigneda“Medium”VRF..
Thisisalsoconsistentwithotherreliabilitystandards(i.e.,BALͲ001Ͳ2,BALͲ003Ͳ1,etc).

•

FERCGuideline3—ConsistencyamongReliabilityStandardsexists.Thisrequirementissimilar
inconcepttothecurrentenforceableBALͲ001Ͳ0.1astandardRequirementsR1andR2,which
haveanapprovedMediumVRF,andapprovedreliabilitystandardsBALͲ001Ͳ1andBALͲ003Ͳ1.

•

FERCGuideline4—ConsistencywithNERC’sDefinitionoftheVRFlevelselectedexists.This
requirement,ifviolated,coulddirectlyaffecttheelectricalstateorthecapabilityoftheBulk
ElectricSystem,ortheabilitytoeffectivelymonitorandcontroltheBulkElectricSystem,but

BALͲ002Ͳ2
VRFandVSLAssignments–July,2013July,2015

6
4

violation,initself,wouldunlikelyresultintheBulkElectricSysteminstability,separation,or
cascadingfailuressincethisrequirementisanafterͲtheͲfactcalculation,notperformedinRealͲ
time.
•

FERCGuideline5—ThisrequirementdoesnotcoͲminglereliabilityobjectives.



BALͲ002Ͳ2
VRFandVSLAssignments–July,2013July,2015

6
5

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
eachrequirementinBALͲ002Ͳ2meettheFERCGuidelinesforassessingVSLs:

BALͲ002Ͳ2
VRFandVSLAssignments–July,2013July,2015

6

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.

BALͲ002Ͳ2
VRFandVSLAssignments–July,2013July,2015

6
7

TheNERCVSL
Guidelinesare
satisfiedby
incorporating
percentageof
noncompliance
performancefor
thecalculated
CPS1.

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

ProposedVSLsarenotbinary.
ProposedVSLlanguagedoesnot
includeambiguoustermsand
ensuresuniformityand
consistencyinthe
determinationofpenalties
basedonlyonthepercentageof
intervalstheentityis
noncompliant.

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

BALͲ002Ͳ2
VRFandVSLAssignments–July,2013
2015


R1

R#

Compliance with
NERC VSL
Guidelines

VSLs for BAL-002-2 Requirement R1:


ProposedVSLsdonot
expandonwhatis
requiredinthe
requirement.TheVSLs
assignedonlyconsider
resultsofthecalculation
required.ProposedVSLs
areconsistentwiththe
requirement.

Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding
Requirement

Guideline 3

July,
8


ProposedVSLsare
basedonsingle
violationsandnota
cumulativeviolation
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.

Thisisanewrequirement.
Asdrafted,theproposed
VSLsdonotlowerthe
currentlevelofcompliance.

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
timetheentityis
noncompliant..

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

BALͲ002Ͳ2
VRFandVSLAssignments–July,2013
2015


R2.

R#

Compliance with
NERC VSL
Guidelines

VSLs for BAL-002-2 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

July,
9


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.

Thisissimilartothecurrent
BALͲ002Ͳ1Requirement
R3.1.Asdrafted,the
proposedVSLsdonotlower
thecurrentlevelof
compliance.

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
contingencyreserve
recovered.

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

BALͲ002Ͳ2
VRFandVSLAssignments–July,2013July,2015

R3.

R#

Compliance with
NERC VSL
Guidelines

VSLs for BAL-002-2 Requirement R3:


10
6

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

Standards Announcement

Project 2010-14.1 Phase 1 of Balancing Authority
Reliability-based Controls
BAL-002-2
Final Ballot Open through October 8, 2015
Now Available

A final ballot for BAL-002-2 – Contingency Reserve for Recovery from Balancing Contingency Event is
open through 8 p.m. Eastern, Thursday, October 8, 2015.
The standard drafting team (SDT) reviewed the responses received from the previous comment period
(July 7 – August 20, 2015). There were several requests for clarification on the SDT’s intent for a couple
of items in the standard. The SDT has added minor clarifying language to the areas identified by the
commenters.
Balloting
In the final ballot, votes are counted by exception. Only members of the ballot pool may cast a vote. All
ballot pool members may change their previously cast vote. 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 pool associated with this project may log in and submit their vote for the standard
here. If you experience any difficulties using the Standards Balloting & Commenting System, 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).
Next Steps

The voting results for the standard will be posted and announced after the ballot closes. If approved, the
standard will be submitted to the Board of Trustees for adoption and then filed with the appropriate
regulatory authorities.
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 | Final Ballot
Project 2010-14.2 BARC BAL-002-2 | September 29 – October 8, 2015

2

Standards Announcement

Project 2010-14.1 Phase 1 of Balancing Authority
Reliability-based Controls
BAL-002-2
Final Ballot Results
Now Available

A final ballot for BAL-002-2 – Disturbance Control Standard – Contingency Reserve for Recovery from a
Balancing Contingency Event concluded 8 p.m. Eastern, Thursday, October 8, 2015.
The standard received sufficient affirmative votes for approval and voting statistics are listed below. The
Ballot Results page provides a link to the detailed results for the ballot.
Ballot
Quorum / Approval
84.28% / 74.61%
Next Steps

The standard will be submitted to the Board of Trustees for adoption and then filed with the appropriate
regulatory authorities.
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

Index - NERC Balloting Tool

NERC Balloting Tool

Dashboard

Users

Ballots

Surveys

Legacy SBS
Login / Register

BALLOT RESULTS
Ballot Name: 2010-14.1 Phase 1 of Balancing Authority Reliability-based Controls BAL-002-2 FN 2 ST
Voting Start Date: 9/29/2015 11:12:55 AM
Voting End Date: 10/8/2015 8:00:00 PM
Ballot Type: ST
Ballot Activity: FN
Ballot Series: 2
Total # Votes: 252
Total Ballot Pool: 299
Quorum: 84.28
Weighted Segment Value: 74.61

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

74

1

41

0.732

15

0.268

0

5

13

Segment:
2

9

0.9

4

0.4

5

0.5

0

0

0

Segment:
3

70

1

39

0.78

11

0.22

0

10

10

Segment:
4

25

1

10

0.769

3

0.231

0

9

3

Segment:
5

66

1

33

0.767

10

0.233

0

10

13

Segment:
6

44

1

24

0.8

6

0.2

0

7

7

Segment:
7

0

0

0

0

0

0

0

0

0

1

0.1

0

0

0

Segment

© 2015
- NERC Ver
ERODVSBSWB01
Segment:
2 1.3.5.11
0.2Machine Name:
1
0.1
8

https://sbs.nerc.net/BallotResults/Index/98[11/2/2015 4:02:19 PM]

Index - NERC Balloting Tool

Segment:
9

2

0.1

1

0.1

0

0

0

0

1

Segment:
10

7

0.7

7

0.7

0

0

0

0

0

Totals:

299

6.9

160

5.148

51

1.752

0

41

47

BALLOT POOL MEMBERS
Show All
All

Segment

Search:

entries

Organization

Voter

Designated
Proxy

Search

Ballot

NERC
Memo

1

Ameren - Ameren
Services

Eric Scott

Affirmative

N/A

1

APS - Arizona Public
Service Co.

Michelle Amarantos

Affirmative

N/A

1

Associated Electric
Cooperative, Inc.

Phil Hart

Negative

N/A

1

Avista - Avista
Corporation

Bryan Cox

Affirmative

N/A

1

Balancing Authority of
Northern California

Kevin Smith

Affirmative

N/A

1

BC Hydro and Power
Authority

Patricia Robertson

Affirmative

N/A

1

Beaches Energy
Services

Don Cuevas

Abstain

N/A

1

Berkshire Hathaway
Energy - MidAmerican
Energy Co.

Terry Harbour

Affirmative

N/A

https://sbs.nerc.net/BallotResults/Index/98[11/2/2015 4:02:19 PM]

Joe Tarantino

Index - NERC Balloting Tool

1

Black Hills Corporation

Wes Wingen

None

N/A

1

Bonneville Power
Administration

Donald Watkins

Affirmative

N/A

1

Bryan Texas Utilities

John Fontenot

Affirmative

N/A

1

Central Electric Power
Cooperative (Missouri)

Michael Bax

Negative

N/A

1

Cleco Corporation

John Lindsey

None

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

Dominion - Dominion
Virginia Power

Larry Nash

Affirmative

N/A

1

Duke Energy

Doug Hils

Affirmative

N/A

1

Edison International Southern California
Edison Company

Steven Mavis

Affirmative

N/A

1

Empire District Electric
Co.

Ralph Meyer

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

Great Plains Energy Kansas City Power and
Light Co.

James McBee

None

N/A

1

Great River Energy

Gordon Pietsch

Negative

N/A

1

Hydro One Networks,
Inc.

Payam Farahbakhsh

None

N/A

1

Hydro-Qu?bec
TransEnergie

Martin Boisvert

Affirmative

N/A

1

IDACORP - Idaho Power
Company

Molly Devine

Affirmative

N/A

https://sbs.nerc.net/BallotResults/Index/98[11/2/2015 4:02:19 PM]

Louis Guidry

Douglas Webb

Index - NERC Balloting Tool

1

International
Transmission Company
Holdings Corporation

Michael Moltane

1

KAMO Electric
Cooperative

1

Abstain

N/A

Walter Kenyon

Negative

N/A

Lincoln Electric System

Doug Bantam

None

N/A

1

Los Angeles Department
of Water and Power

faranak sarbaz

Affirmative

N/A

1

Lower Colorado River
Authority

Teresa Cantwell

Abstain

N/A

1

M and A Electric Power
Cooperative

William Price

Negative

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

Affirmative

N/A

1

N.W. Electric Power
Cooperative, Inc.

Mark Ramsey

Negative

N/A

1

National Grid USA

Michael Jones

Abstain

N/A

1

NB Power Corporation

Alan MacNaughton

Negative

N/A

1

Nebraska Public Power
District

Jamison Cawley

Negative

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.

Robert Fox

Negative

N/A

1

Northeast Missouri
Electric Power
Cooperative

Kevin White

Negative

N/A

1

NorthWestern Energy

Belinda Tierney

None

N/A

https://sbs.nerc.net/BallotResults/Index/98[11/2/2015 4:02:19 PM]

Meghan
Ferguson

Scott Miller

Index - NERC Balloting Tool

1

OGE Energy Oklahoma Gas and
Electric Co.

Terri Pyle

Negative

N/A

1

Ohio Valley Electric
Corporation

Scott Cunningham

None

N/A

1

Omaha Public Power
District

Doug Peterchuck

Abstain

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

None

N/A

1

PNM Resources - Public
Service Company of
New Mexico

Laurie Williams

Affirmative

N/A

1

Portland General
Electric Co.

John Walker

Affirmative

N/A

1

PPL Electric Utilities
Corporation

Brenda Truhe

Negative

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

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

Negative

N/A

1

Seattle City Light

Pawel Krupa

Affirmative

N/A

https://sbs.nerc.net/BallotResults/Index/98[11/2/2015 4:02:19 PM]

Joe Tarantino

Index - NERC Balloting Tool

1

Seminole Electric
Cooperative, Inc.

Mark Churilla

1

Sho-Me Power Electric
Cooperative

1

Affirmative

N/A

Denise Stevens

Negative

N/A

Southern Company Southern Company
Services, Inc.

Robert A. Schaffeld

Affirmative

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

None

N/A

1

U.S. Bureau of
Reclamation

Richard Jackson

None

N/A

1

United Illuminating Co.

Jonathan Appelbaum

Affirmative

N/A

1

Western Area Power
Administration

Steve Johnson

Affirmative

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

Negative

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

PJM Interconnection,

Mark Holman

Affirmative

N/A

https://sbs.nerc.net/BallotResults/Index/98[11/2/2015 4:02:19 PM]

Bret Galbraith

Kathleen
Goodman

Index - NERC Balloting Tool

L.L.C.
2

Southwest Power Pool,
Inc. (RTO)

Charles Yeung

Negative

N/A

3

Ameren - Ameren
Services

David Jendras

Affirmative

N/A

3

APS - Arizona Public
Service Co.

Jeri Freimuth

Affirmative

N/A

3

Associated Electric
Cooperative, Inc.

Todd Bennett

Negative

N/A

3

Austin Energy

Shuye Teng

Abstain

N/A

3

Avista - Avista
Corporation

Scott Kinney

Affirmative

N/A

3

BC Hydro and Power
Authority

Pat Harrington

Affirmative

N/A

3

Beaches Energy
Services

Steven Lancaster

Abstain

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

None

N/A

3

City of Green Cove
Springs

Mark Schultz

Abstain

N/A

3

City of Leesburg

Chris Adkins

Abstain

N/A

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

Abstain

N/A

3

Con Ed - Consolidated
Edison Co. of New York

Peter Yost

Affirmative

N/A

https://sbs.nerc.net/BallotResults/Index/98[11/2/2015 4:02:19 PM]

Darnez
Gresham

Bill Hughes

Louis Guidry

Index - NERC Balloting Tool

3

Dominion - Dominion
Resources, Inc.

Connie Lowe

Affirmative

N/A

3

DTE Energy - Detroit
Edison Company

Kent Kujala

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

Abstain

N/A

3

Florida Power & Light

Summer Esquerre

None

N/A

3

Georgia System
Operations Corporation

Scott McGough

Abstain

N/A

3

Grand River Dam
Authority

Jeff Wells

Affirmative

N/A

3

Great Plains Energy Kansas City Power and
Light Co.

Jessica Tucker

None

N/A

3

Great River Energy

Brian Glover

Negative

N/A

3

KAMO Electric
Cooperative

Ted Hilmes

None

N/A

3

Lakeland Electric

Mace Hunter

Abstain

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

Negative

N/A

3

Manitoba Hydro

Karim Abdel-Hadi

Affirmative

N/A

3

MEAG Power

Roger Brand

Affirmative

N/A

https://sbs.nerc.net/BallotResults/Index/98[11/2/2015 4:02:19 PM]

Douglas Webb

Scott Miller

Index - NERC Balloting Tool

3

Modesto Irrigation
District

Jack Savage

3

Muscatine Power and
Water

3

Affirmative

N/A

Seth Shoemaker

Negative

N/A

National Grid USA

Brian Shanahan

Abstain

N/A

3

Nebraska Public Power
District

Tony Eddleman

Negative

N/A

3

New York Power
Authority

David Rivera

Affirmative

N/A

3

NiSource - Northern
Indiana Public Service
Co.

Ramon Barany

Negative

N/A

3

Northeast Missouri
Electric Power
Cooperative

Skyler Wiegmann

None

N/A

3

NW Electric Power
Cooperative, Inc.

John Stickley

Negative

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

Platte River Power
Authority

Jeff Landis

None

N/A

3

PNM Resources

Michael Mertz

Affirmative

N/A

3

Portland General
Electric Co.

Thomas Ward

Affirmative

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

https://sbs.nerc.net/BallotResults/Index/98[11/2/2015 4:02:19 PM]

Nick Braden

Index - NERC Balloting Tool

3

Sacramento Municipal
Utility District

Rachel Moore

3

Salt River Project

3

Affirmative

N/A

John Coggins

Affirmative

N/A

Santee Cooper

James Poston

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

Negative

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

3

Turlock Irrigation District

James Ramos

Affirmative

N/A

3

WEC Energy Group, Inc.

James Keller

Negative

N/A

3

Westar Energy

Bo Jones

None

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

Duane Dahlquist

Affirmative

N/A

https://sbs.nerc.net/BallotResults/Index/98[11/2/2015 4:02:19 PM]

Joe Tarantino

Index - NERC Balloting Tool

Agency
4

City of Clewiston

Lynne Mila

Abstain

N/A

4

City of New Smyrna
Beach Utilities
Commission

Tim Beyrle

Abstain

N/A

4

City of Redding

Nick Zettel

None

N/A

4

City of Winter Park

Mark Brown

None

N/A

4

CMS Energy Consumers Energy
Company

Julie Hegedus

Abstain

N/A

4

DTE Energy - Detroit
Edison Company

Daniel Herring

Affirmative

N/A

4

FirstEnergy - Ohio
Edison Company

Doug Hohlbaugh

Affirmative

N/A

4

Flathead Electric
Cooperative

Russ Schneider

Abstain

N/A

4

Florida Municipal Power
Agency

Carol Chinn

Abstain

N/A

4

Fort Pierce Utilities
Authority

Thomas Parker

Abstain

N/A

4

Georgia System
Operations Corporation

Guy Andrews

Abstain

N/A

4

Keys Energy Services

Stanley Rzad

Abstain

N/A

4

MGE Energy - Madison
Gas and Electric Co.

Joseph DePoorter

Negative

N/A

4

Modesto Irrigation
District

Spencer Tacke

Negative

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

Affirmative

N/A

4

Sacramento Municipal
Utility District

Michael Ramirez

Affirmative

N/A

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Mary Downey

Joe Tarantino

Index - NERC Balloting Tool

4

Seattle City Light

Hao Li

Affirmative

N/A

4

Seminole Electric
Cooperative, Inc.

Michael Ward

Affirmative

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

Negative

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

Negative

N/A

5

Austin Energy

Jeanie Doty

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

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

City of Redding

Paul Cummings

Mary Downey

None

N/A

5

Cleco Corporation

Stephanie Huffman

Louis Guidry

None

N/A

5

CMS Energy Consumers Energy
Company

David Greyerbiehl

Abstain

N/A

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Index - NERC Balloting Tool

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

Dairyland Power
Cooperative

Tommy Drea

None

N/A

5

Dominion - Dominion
Resources, Inc.

Randi Heise

Affirmative

N/A

5

DTE Energy - Detroit
Edison Company

Jeffrey DePriest

Affirmative

N/A

5

Duke Energy

Dale Goodwine

Affirmative

N/A

5

Dynegy Inc.

Dan Roethemeyer

Negative

N/A

5

Edison International Southern California
Edison Company

Michael McSpadden

Affirmative

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

Abstain

N/A

5

Great Plains Energy Kansas City Power and
Light Co.

Harold Wyble

None

N/A

5

Great River Energy

Preston Walsh

Negative

N/A

5

Hydro-Qu?bec
Production

Roger Dufresne

Affirmative

N/A

5

JEA

John Babik

Affirmative

N/A

5

Lakeland Electric

Jim Howard

Abstain

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

Abstain

N/A

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Index - NERC Balloting Tool

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

NaturEner USA, LLC

Jamie Lynn Bussin

Affirmative

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

Affirmative

N/A

5

NextEra Energy

Allen Schriver

Affirmative

N/A

5

NiSource - Northern
Indiana Public Service
Co.

Michael Melvin

Negative

N/A

5

OGE Energy Oklahoma Gas and
Electric Co.

Leo Staples

None

N/A

5

Omaha Public Power
District

Mahmood Safi

Abstain

N/A

5

OTP - Otter Tail Power
Company

Cathy Fogale

Negative

N/A

5

Platte River Power
Authority

Tyson Archie

Affirmative

N/A

5

Portland General
Electric Co.

Matt Jastram

None

N/A

5

PowerSouth Energy
Cooperative

Tim Hattaway

None

N/A

5

PPL Electric Utilities
Corporation

Dan Wilson

Negative

N/A

5

PSEG - PSEG Fossil
LLC

Tim Kucey

None

N/A

https://sbs.nerc.net/BallotResults/Index/98[11/2/2015 4:02:19 PM]

Scott Miller

Index - NERC Balloting Tool

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

Santee Cooper

Lewis Pierce

None

N/A

5

SCANA - South Carolina
Electric and Gas Co.

Edward Magic

Negative

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

None

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

U.S. Bureau of
Reclamation

Erika Doot

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

Brian Ackermann

Negative

N/A

https://sbs.nerc.net/BallotResults/Index/98[11/2/2015 4:02:19 PM]

Joe Tarantino

Dennis
Chastain

Index - NERC Balloting Tool

Cooperative, Inc.
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

Mary Downey

None

N/A

6

Cleco Corporation

Robert Hirchak

Louis Guidry

None

N/A

6

Colorado Springs
Utilities

Shannon Fair

None

N/A

6

Con Ed - Consolidated
Edison Co. of New York

Robert Winston

Negative

N/A

6

Dominion - Dominion
Resources, Inc.

Louis Slade

Affirmative

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

Abstain

N/A

6

Florida Municipal Power
Pool

Tom Reedy

Abstain

N/A

6

Great Plains Energy Kansas City Power and
Light Co.

Chris Bridges

None

N/A

6

Great River Energy

Donna Stephenson

Negative

N/A

6

Lincoln Electric System

Eric Ruskamp

Abstain

N/A

6

Lower Colorado River
Authority

Michael Shaw

Abstain

N/A

6

Luminant - Luminant
Energy

Brenda Hampton

Abstain

N/A

6

Manitoba Hydro

Blair Mukanik

Affirmative

N/A

https://sbs.nerc.net/BallotResults/Index/98[11/2/2015 4:02:19 PM]

Michael
Brytowski

Index - NERC Balloting Tool

6

Modesto Irrigation
District

James McFall

6

Muscatine Power and
Water

6

Affirmative

N/A

Ryan Streck

Negative

N/A

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

Negative

N/A

6

OGE Energy Oklahoma Gas and
Electric Co.

Jerry Nottnagel

Abstain

N/A

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

N/A

6

PSEG - PSEG Energy
Resources and Trade
LLC

Karla Jara

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

John J. Ciza

Affirmative

N/A

https://sbs.nerc.net/BallotResults/Index/98[11/2/2015 4:02:19 PM]

Nick Braden

John Hare

Joe Tarantino

Index - NERC Balloting Tool

Marketing
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

Xcel Energy, Inc.

Peter Colussy

Affirmative

N/A

8

David Kiguel

David Kiguel

Negative

N/A

8

Massachusetts Attorney
General

Frederick Plett

Affirmative

N/A

9

City of Vero Beach

Ginny Beigel

None

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

Affirmative

N/A

10

Northeast Power
Coordinating Council

Guy V. Zito

Affirmative

N/A

10

ReliabilityFirst

Anthony Jablonski

Affirmative

N/A

10

SERC Reliability
Corporation

David Greene

Affirmative

N/A

10

Texas Reliability Entity,
Inc.

Rachel Coyne

Affirmative

N/A

10

Western Electricity
Coordinating Council

Steven Rueckert

Affirmative

N/A

Previous
Showing 1 to 299 of 299 entries

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1

Next

Exhibit I
Mapping Document for BAL-002-2

Project 2010-14.1 Mapping Document

Transition of BAL-002-0 to BAL-002-2

Requirement in
Approved Standard
BAL-002-0 R1

BAL-002-0 R2

BAL-002-0 R3

BAL-002-0 R4

Standard: BAL-002-0 – Disturbance Control Standard
Transitions to the below Requirement in
Description and Change Justification
New Standard or Other Action
This Requirement has been moved into BALThis requirement does not provide for a reliability outcome and if
002-2 Applicability and “Additional
violated would not cause separation, instability or cascading outages.
Compliance Information” sections
This requirement falls under the Paragraph 81 rules. This requirement
This requirement has been removed from
defines a commercial agreement between the BA involved in the
BAL-002-2
RSG. This requirement does not provide for a reliability outcome and
if violated would not cause separation, instability or cascading
outages.
This
requirement was broken apart. The requirement was defining two
Requirement R1 and R2
separate actions; 1) to require activation of Contingency Reserves, and
2) to require having Contingency Reserves equal to its MSSC.
Requirement R1 mandates recovery from a Reportable Balancing
This Requirement has been moved into BAL- Contingency Event.
002-2 Requirement R1 and into the
“Contingency Event Recovery Period”
A portion of this requirement was defining the timing for recovery from
definition.
an event. This has now been defined and has been proposed to be
added to the NERC Glossary of Terms.

Requirement in
Approved Standard
BAL-002-0 R5

BAL-002-0 R6

Standard: BAL-002-0 – Disturbance Control Standard
Transitions to the below Requirement in
Description and Change Justification
New Standard or Other Action
This Requirement has been moved into BALA portion of this requirement was defining how a RSG calculates its
002-2 Requirement R1 and “Reserve Sharing
ACE. This has now been defined and has been proposed to be added
Group Reporting ACE” definition.
to the NERC Glossary of Terms.
This Requirement has been moved into the
BAL-002-2 Requirement R3 and
“Contingency Event Restoration Period”
definition.

Requirement R3 mandates restoration of Contingency Reserve
following a Balancing Contingency Event.
A portion of this requirement was defining the timing for restoration of
Contingency Reserve after an event. This has now been defined and
has been proposed to be added to the NERC Glossary of Terms.

2

Exhibit J
Mapping Document for EOP-011

Project 2009-03 - Emergency Operations
Mapping Document
Project Purpose

The Emergency Operations Five-Year Review Team (EOP FYRT) was appointed by the Standards Committee Executive Committee on April
22, 2013. The EOP FYRT has reviewed the following Emergency Operations standards: EOP-001-2.1b, EOP-002-3.1 and EOP-003-2 to decide
if revisions are needed in the scope of this project in relation to P81 and FERC directives. This project is a comprehensive review of this set
of EOP standards to ensure that the requirements are clear and unambiguous. Many of the requirements in this set of standards were
translated from Operating Policies as part of the Version 0 process, and the standards were due for a comprehensive review. Suggestions
for improvement, possible consolidation and for requirements to be considered for retirement under Paragraph 81 have been submitted by
stakeholders, other drafting teams and FERC staff.
On October 17, 2013 the Standards Committee accepted the recommendations of the EOP FYRT and appointed a drafting team to
implement the recommendations and begin formal development. The Standards Committee further authorized the posting of the Standard
Authorization Request (SAR) developed by the EOP FYRT.
Project 2009-03 – Emergency Operations (EOP-011-1) is being coordinated with Project 2008-02 – Undervoltage Load Shedding, which
proposes to retire EOP-003-2 Requirements R2, R4, and R7 since these requirements are proposed to be covered by PRC-010-1,
Requirement R1; this translation is illustrated in this document and will also be referenced in Project 2008-02’s mapping document. The
project schedules and implementation plans for these two projects are being closely coordinated to ensure that no gaps or duplication will
result from the products developed by the two drafting teams.

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-001-2.1b, Emergency Operations Planning
Requirement in Approved Standard

R1. Balancing Authorities shall have operating
agreements with adjacent Balancing Authorities that
shall, at a minimum, contain provisions for emergency
assistance, including provisions to obtain emergency
assistance from remote Balancing Authorities.

Translation to
New Standard or
Other Action

Comments

Translated to EOP011-1, Emergency
Operations.

EOP-011-1, R2
R2.
Each Balancing Authority shall develop, maintain,
and implement a Reliability Coordinator-reviewed
Operating Plan(s) to mitigate Capacity Emergencies and
Energy Emergencies within its Balancing Authority Area.
The Operating Plan(s) shall include the following, as
applicable: [Violation Risk Factor: High] [Time Horizon:
Real-Time Operations, Operations Planning, Long-term
Planning]
2.1. Roles and responsibilities for activating the
Operating Plan(s);
2.2. Processes to prepare for and mitigate Emergencies
including:
2.2.1.
Notification to its Reliability Coordinator, to
include current and projected conditions
when experiencing a Capacity Emergency or
Energy Emergency;
2.2.2
Requesting an Energy Emergency Alert, per
Attachment 1;

Mapping Document

2

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-001-2.1b, Emergency Operations Planning
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

2.2.3.

Managing generating resources in its
Balancing Authority Area to address:
2.2.3.1. capability and availability;
2.2.3.2. fuel supply and inventory concerns;
2.2.3.3. fuel switching capabilities; and
2.2.3.4. environmental constraints.
2.2.4.
Public appeals for voluntary Load
reductions;
2.2.5.
Requests to government agencies to
implement their programs to achieve
necessary energy reductions;
2.2.6.
Reduction of internal utility energy use;
2.2.7.
Use of Interruptible Load, curtailable Load
and demand response;
2.2.8.
Provisions for operator-controlled manual
Load shedding that minimizes the overlap
with automatic Load shedding and are
capable of being implemented in a
timeframe adequate for mitigating the
Emergency; and
2.2.9.
Reliability impacts of extreme weather
conditions.
Mapping Document

3

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-001-2.1b, Emergency Operations Planning
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

R2. Each Transmission Operator and Balancing
Authority shall:
R2.1. Develop, maintain, and implement a set of
plans to mitigate operating emergencies
for insufficient generating capacity.
R2.2. Develop, maintain, and implement a set of
plans to mitigate operating emergencies
on the transmission system.
R2.3. Develop, maintain, and implement a set of
plans for load shedding

Translated to EOP011-1, Emergency
Operations.

EOP-011-1, R1
R1. Each Transmission Operator shall develop,
maintain, and implement a Reliability Coordinatorreviewed Operating Plan(s) to mitigate operating
Emergencies in its Transmission Operator Area. The
Operating Plan(s) shall include the following, as
applicable: [Violation Risk Factor: High] [Time
Horizon: Real-Time Operations, Operations
Planning, Long-term Planning]
1.1. Roles and responsibilities for activating the
Operating Plan(s);
1.2. Processes to prepare for and mitigate Emergencies
including:
1.2.1. Notification to its Reliability Coordinator, to
include current and projected conditions, when
experiencing an operating Emergency;
1.2.2. Cancellation or recall of Transmission and
generation outages;
1.2.3. Transmission system reconfiguration;
1.2.4. Redispatch of generation request;

Mapping Document

4

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-001-2.1b, Emergency Operations Planning
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

1.2.5. Provisions for operator-controlled manual
Load shedding that minimizes the overlap with
automatic Load shedding and are capable of
being implemented in a timeframe adequate
for mitigating the Emergency; and
1.2.6. Reliability impacts of extreme weather
conditions; and
EOP-011-1, R2
R2.
Each Balancing Authority shall develop, maintain,
and implement a Reliability Coordinator-reviewed
Operating Plan(s) to mitigate Capacity Emergencies and
Energy Emergencies within its Balancing Authority Area.
The Operating Plan(s) shall include the following, as
applicable: [Violation Risk Factor: High] [Time Horizon:
Real-Time Operations, Operations Planning, Long-term
Planning]
2.1. Roles and responsibilities for activating the
Operating Plan(s);
2.2. Processes to prepare for and mitigate Emergencies
including:

Mapping Document

5

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-001-2.1b, Emergency Operations Planning
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

2.2.1.

Notification to its Reliability Coordinator, to
include current and projected conditions
when experiencing a Capacity Emergency or
Energy Emergency;
2.2.2
Requesting an Energy Emergency Alert, per
Attachment 1;
2.2.3.
Managing generating resources in its
Balancing Authority Area to address:
2.2.3.1. capability and availability;
2.2.3.2. fuel supply and inventory concerns;
2.2.3.3. fuel switching capabilities; and
2.2.3.4. environmental constraints.
2.2.4.
Public appeals for voluntary Load
reductions;
2.2.5.
Requests to government agencies to
implement their programs to achieve
necessary energy reductions;
2.2.6.
Reduction of internal utility energy use;
2.2.7.
Use of Interruptible Load, curtailable Load
and demand response;
2.2.8.
Provisions for operator-controlled manual
Load shedding that minimizes the overlap
Mapping Document

6

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-001-2.1b, Emergency Operations Planning
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

2.2.9.

R3. Each Transmission Operator and Balancing
Authority shall have emergency plans that will enable it
to mitigate operating emergencies. At a minimum,
Transmission Operator and
Balancing Authority emergency plans shall include:
R3.1. Communications protocols to be used
during emergencies.
R3.2. A list of controlling actions to resolve the
emergency. Load reduction, in sufficient
quantity to resolve the emergency within
NERC-established timelines, shall be one of
the controlling actions.

Mapping Document

with automatic Load shedding and are
capable of being implemented in a
timeframe adequate for mitigating the
Emergency; and
Reliability impacts of extreme weather
conditions.

Translated to EOP- EOP-011-1, R1
011-1, Emergency
R1. Each Transmission Operator shall develop,
Operations; Retired
maintain, and implement a Reliability CoordinatorR3.1 under Criteria
reviewed Operating Plan(s) to mitigate operating
A and B7 of
Emergencies in its Transmission Operator Area. The
Paragraph 81
Operating Plan(s) shall include the following, as
guidelines; Retired
applicable: [Violation Risk Factor: High] [Time
R3.4 under Criteria
Horizon: Real-Time Operations, Operations
A and B1 of
Planning, Long-term Planning]
Paragraph 81
1.1. Roles and responsibilities for activating the
guidelines.
Operating Plan(s);
1.2. Processes to prepare for and mitigate Emergencies
including:

7

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-001-2.1b, Emergency Operations Planning
Requirement in Approved Standard

R3.3. The tasks to be coordinated with and
among adjacent Transmission Operators
and Balancing Authorities.
R3.4. Staffing levels for the emergency.

Translation to
New Standard or
Other Action

Comments

1.2.1. Notification to its Reliability Coordinator, to
include current and projected conditions, when
experiencing an operating Emergency;
1.2.2. Cancellation or recall of Transmission and
generation outages;
1.2.3. Transmission system reconfiguration;
1.2.4. Redispatch of generation request;
1.2.5. Provisions for operator-controlled manual
Load shedding that minimizes the overlap with
automatic Load shedding and are capable of
being implemented in a timeframe adequate
for mitigating the Emergency; and
1.2.6. Reliability impacts of extreme weather
conditions; and
EOP-011-1, R2
R2.
Each Balancing Authority shall develop, maintain,
and implement a Reliability Coordinator-reviewed
Operating Plan(s) to mitigate Capacity Emergencies and
Energy Emergencies within its Balancing Authority Area.
The Operating Plan(s) shall include the following, as
applicable: [Violation Risk Factor: High] [Time Horizon:

Mapping Document

8

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-001-2.1b, Emergency Operations Planning
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

Real-Time Operations, Operations Planning, Long-term
Planning]
2.1. Roles and responsibilities for activating the
Operating Plan(s);
2.2. Processes to prepare for and mitigate Emergencies
including:
2.2.1.
Notification to its Reliability Coordinator, to
include current and projected conditions
when experiencing a Capacity Emergency or
Energy Emergency;
2.2.2
Requesting an Energy Emergency Alert, per
Attachment 1;
2.2.3.
Managing generating resources in its
Balancing Authority Area to address:
2.2.3.1. capability and availability;
2.2.3.2. fuel supply and inventory concerns;
2.2.3.3. fuel switching capabilities; and
2.2.3.4. environmental constraints.
2.2.4.
Public appeals for voluntary Load
reductions;

Mapping Document

9

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-001-2.1b, Emergency Operations Planning
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

2.2.5.

Requests to government agencies to
implement their programs to achieve
necessary energy reductions;
2.2.6.
Reduction of internal utility energy use;
2.2.7.
Use of Interruptible Load, curtailable Load
and demand response;
2.2.8.
Provisions for operator-controlled manual
Load shedding that minimizes the overlap
with automatic Load shedding and are
capable of being implemented in a
timeframe adequate for mitigating the
Emergency; and
2.2.9.
Reliability impacts of extreme weather
conditions.
Retirements:
Requirement R3.1
• Meets Criterion B7 and Criterion A of Paragraph 81;
• Covered by EOP-001-2.1b Requirement R4 in
Attachment 1 (proposed Requirements R1 and R2 in
EOP-011-1); and

Mapping Document

10

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-001-2.1b, Emergency Operations Planning
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

•

COM-001 and COM-002 are descriptive in the
identification of protocols to use and, thus, adequately
cover the generic reference.

Requirement R3.2
• Meets Criterion B7 and Criterion A of Paragraph 81;
and
• Load reduction within timelines is covered by BAL002 Requirement R2.
Requirement R3.4
• Meets Criterion B1 of Paragraph 81; and
• Staffing levels are administrative in nature.
R4. Each Transmission Operator and Balancing
Authority shall include the applicable elements in
Attachment 1-EOP-001 when developing an emergency
plan.

Mapping Document

Translated to EOP011-1, Emergency
Operations.

EOP-011-1, R1
R1. Each Transmission Operator shall develop,
maintain, and implement a Reliability Coordinatorreviewed Operating Plan(s) to mitigate operating
Emergencies in its Transmission Operator Area. The
Operating Plan(s) shall include the following, as
applicable: [Violation Risk Factor: High] [Time

11

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-001-2.1b, Emergency Operations Planning
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

Horizon: Real-Time Operations, Operations
Planning, Long-term Planning]
1.1. Roles and responsibilities for activating the
Operating Plan(s);
1.2. Processes to prepare for and mitigate Emergencies
including:
1.2.1. Notification to its Reliability Coordinator, to
include current and projected conditions, when
experiencing an operating Emergency;
1.2.2. Cancellation or recall of Transmission and
generation outages;
1.2.3. Transmission system reconfiguration;
1.2.4. Redispatch of generation request;
1.2.5. Provisions for operator-controlled manual
Load shedding that minimizes the overlap with
automatic Load shedding and are capable of
being implemented in a timeframe adequate
for mitigating the Emergency; and
1.2.6. Reliability impacts of extreme weather
conditions; and
EOP-011-1, R2

Mapping Document

12

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-001-2.1b, Emergency Operations Planning
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

R2.
Each Balancing Authority shall develop, maintain,
and implement a Reliability Coordinator-reviewed
Operating Plan(s) to mitigate Capacity Emergencies and
Energy Emergencies within its Balancing Authority Area.
The Operating Plan(s) shall include the following, as
applicable: [Violation Risk Factor: High] [Time Horizon:
Real-Time Operations, Operations Planning, Long-term
Planning]
2.1. Roles and responsibilities for activating the
Operating Plan(s);
2.2. Processes to prepare for and mitigate
Emergencies including:
2.2.1.
Notification to its Reliability Coordinator, to
include current and projected conditions
when experiencing a Capacity Emergency or
Energy Emergency;
2.2.2
Requesting an Energy Emergency Alert, per
Attachment 1;
2.2.3.
Managing generating resources in its
Balancing Authority Area to address:
2.2.3.1. capability and availability;
2.2.3.2. fuel supply and inventory concerns;
Mapping Document

13

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-001-2.1b, Emergency Operations Planning
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

2.2.3.3. fuel switching capabilities; and
2.2.3.4. environmental constraints.
2.2.4.
Public appeals for voluntary Load
reductions;
2.2.5.
Requests to government agencies to
implement their programs to achieve
necessary energy reductions;
2.2.6.
Reduction of internal utility energy use;
2.2.7.
Use of Interruptible Load, curtailable Load
and demand response;
2.2.8.
Provisions for operator-controlled manual
Load shedding that minimizes the overlap
with automatic Load shedding and are
capable of being implemented in a
timeframe adequate for mitigating the
Emergency; and
2.2.9.
Reliability impacts of extreme weather
conditions.
R5. The Transmission Operator and Balancing Authority
shall annually review and update each emergency plan.
The Transmission Operator and Balancing Authority
Mapping Document

Translated to EOP011-1, Emergency
Operations.

EOP-011-1, R1
R1. Each Transmission Operator shall develop,
maintain, and implement a Reliability Coordinator-

14

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-001-2.1b, Emergency Operations Planning
Requirement in Approved Standard

shall provide a copy of its updated emergency plans to
its Reliability Coordinator and to neighboring
Transmission Operators and Balancing Authorities.

Mapping Document

Translation to
New Standard or
Other Action

Comments

reviewed Operating Plan(s) to mitigate operating
Emergencies in its Transmission Operator Area. The
Operating Plan(s) shall include the following, as
applicable: [Violation Risk Factor: High] [Time
Horizon: Real-Time Operations, Operations
Planning, Long-term Planning]
1.1. Roles and responsibilities for activating the
Operating Plan(s);
1.2. Processes to prepare for and mitigate Emergencies
including:
1.2.1. Notification to its Reliability Coordinator, to
include current and projected conditions, when
experiencing an operating Emergency;
1.2.2. Cancellation or recall of Transmission and
generation outages;
1.2.3. Transmission system reconfiguration;
1.2.4. Redispatch of generation request;
1.2.5. Provisions for operator-controlled manual
Load shedding that minimizes the overlap with
automatic Load shedding and are capable of
being implemented in a timeframe adequate
for mitigating the Emergency; and

15

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-001-2.1b, Emergency Operations Planning
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

1.2.6. Reliability impacts of extreme weather
conditions; and
EOP-011-1, R2
R2.
Each Balancing Authority shall develop, maintain,
and implement a Reliability Coordinator-reviewed
Operating Plan(s) to mitigate Capacity Emergencies and
Energy Emergencies within its Balancing Authority Area.
The Operating Plan(s) shall include the following, as
applicable: [Violation Risk Factor: High] [Time Horizon:
Real-Time Operations, Operations Planning, Long-term
Planning]
2.1. Roles and responsibilities for activating the
Operating Plan(s);
2.2. Processes to prepare for and mitigate
Emergencies including:
2.2.1.
Notification to its Reliability Coordinator, to
include current and projected conditions
when experiencing a Capacity Emergency or
Energy Emergency;
2.2.2
Requesting an Energy Emergency Alert, per
Attachment 1;
Mapping Document

16

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-001-2.1b, Emergency Operations Planning
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

2.2.3.

Managing generating resources in its
Balancing Authority Area to address:
2.2.3.1. capability and availability;
2.2.3.2. fuel supply and inventory concerns;
2.2.3.3. fuel switching capabilities; and
2.2.3.4. environmental constraints.
2.2.4.
Public appeals for voluntary Load
reductions;
2.2.5.
Requests to government agencies to
implement their programs to achieve
necessary energy reductions;
2.2.6.
Reduction of internal utility energy use;
2.2.7.
Use of Interruptible Load, curtailable Load
and demand response;
2.2.8.
Provisions for operator-controlled manual
Load shedding that minimizes the overlap
with automatic Load shedding and are
capable of being implemented in a
timeframe adequate for mitigating the
Emergency; and
2.2.9.
Reliability impacts of extreme weather
conditions.
Mapping Document

17

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-001-2.1b, Emergency Operations Planning
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

R4. Each Transmission Operator and Balancing Authority
shall address any reliability risks identified by its
Reliability Coordinator pursuant to Requirement R3 and
resubmit its Operating Plan(s) to the Reliability
Coordinator within a time period specified by its
Reliability Coordinator. [Violation Risk Factor: High]
[Time Horizon: Operation Planning]
In this industry it is widely understood that “maintain,” is
not simply to establish the plan. The intent of the EOP
SDT is for BAs and TOPs to keep its Operating Plan(s) to
mitigate Capacity Emergencies and Energy Emergencies
contemporary and for the Emergency Plan to stay
contemporary.
R6. The Transmission Operator and Balancing Authority
shall coordinate its emergency plans with other
Transmission Operators and Balancing Authorities as
appropriate. This coordination includes the following
steps, as applicable:
Mapping Document

Retired under
Criteria B6 and B7
of P81 guidelines.

Retirements
Requirement R6.1
• Meets Criterion B7 of Paragraph 81; and
• Redundant with COM-001.

18

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-001-2.1b, Emergency Operations Planning
Requirement in Approved Standard

R6.1. The Transmission Operator and Balancing
Authority shall establish and maintain
reliable communications between
interconnected systems.
R6.2. The Transmission Operator and Balancing
Authority shall arrange new interchange
agreements to provide for emergency
capacity or energy transfers if existing
agreements cannot be used.
R6.3. The Transmission Operator and Balancing
Authority shall coordinate transmission
and generator maintenance schedules to
maximize capacity or conserve the fuel in
short supply. (This includes water for hydro
generators.)
R6.4. The Transmission Operator and Balancing
Authority shall arrange deliveries of
electrical energy or fuel from remote
systems through normal operating
channels.

Mapping Document

Translation to
New Standard or
Other Action

Comments

Requirement R6.2
• Meets Criterion B6 of Paragraph 81;
• Speaks to an action to be taken during capacity
issues that is not feasible in accomplishing; and
• Transaction arrangements are a commercial
practice.
Requirement R6.3
• Meets Criterion B7 of Paragraph 81; and
• Covered by EOP-001-2.1b Requirement R4 in
Attachment 1 (proposed Requirements R1 and R2
in EOP-011-1).
Requirement R6.4
• Meets Criterion A of Paragraph 81; and
• Does not provide benefit to the reliability of the
BES.

19

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-002-3.1, Capacity and Energy Emergencies
Requirement in Approved Standard

R1. Each Balancing Authority and Reliability Coordinator
shall have the responsibility and clear decision-making
authority to take whatever actions are needed to
ensure the reliability of its respective area and shall
exercise specific authority to alleviate capacity and
energy emergencies.

Translation to
New Standard or
Other Action

Comments

Retired under
Criteria A and B7 of
P81 guidelines.

Retired – redundant with PER-001, R1 with respect to
the Balancing Authority and IRO-001-1.1, Requirement
R3 for the Reliability Coordinator.

R2. Each Balancing Authority shall, when required and
Translated to EOPas appropriate, take one or more actions as described in 011-1, Emergency
its capacity and energy emergency plan to reduce risks
Operations.
to the interconnected system.

Mapping Document

EOP-011-1, R2
R2.
Each Balancing Authority shall develop, maintain,
and implement a Reliability Coordinator-reviewed
Operating Plan(s) to mitigate Capacity Emergencies and
Energy Emergencies within its Balancing Authority Area.
The Operating Plan(s) shall include the following, as
applicable: [Violation Risk Factor: High] [Time Horizon:
Real-Time Operations, Operations Planning, Long-term
Planning]
2.1. Roles and responsibilities for activating the
Operating Plan(s);
2.2. Processes to prepare for and mitigate
Emergencies including:

20

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-002-3.1, Capacity and Energy Emergencies
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

2.2.1.

Notification to its Reliability Coordinator, to
include current and projected conditions
when experiencing a Capacity Emergency or
Energy Emergency;
2.2.2
Requesting an Energy Emergency Alert, per
Attachment 1;
2.2.3.
Managing generating resources in its
Balancing Authority Area to address:
2.2.3.1. capability and availability;
2.2.3.2. fuel supply and inventory concerns;
2.2.3.3. fuel switching capabilities; and
2.2.3.4. environmental constraints.
2.2.4.
Public appeals for voluntary Load
reductions;
2.2.5.
2.2.6.
2.2.7.

Mapping Document

Requests to government agencies to
implement their programs to achieve
necessary energy reductions;
Reduction of internal utility energy use;
Use of Interruptible Load, curtailable Load
and demand response;

21

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-002-3.1, Capacity and Energy Emergencies
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

2.2.8.

2.2.9.
R3. A Balancing Authority that is experiencing an
operating capacity or energy emergency shall
communicate its current and future system conditions
to its Reliability Coordinator and neighboring Balancing
Authorities.

Mapping Document

Translated to EOP011-1, Emergency
Operations.

Provisions for operator-controlled manual
Load shedding that minimizes the overlap
with automatic Load shedding and are
capable of being implemented in a
timeframe adequate for mitigating the
Emergency; and
Reliability impacts of extreme weather
conditions.

EOP-011-1, R2
R2.
Each Balancing Authority shall develop, maintain,
and implement a Reliability Coordinator-reviewed
Operating Plan(s) to mitigate Capacity Emergencies and
Energy Emergencies within its Balancing Authority Area.
The Operating Plan(s) shall include the following, as
applicable: [Violation Risk Factor: High] [Time Horizon:
Real-Time Operations, Operations Planning, Long-term
Planning]
2.1. Roles and responsibilities for activating the
Operating Plan(s);

22

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-002-3.1, Capacity and Energy Emergencies
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

2.2. Processes to prepare for and mitigate Emergencies
including:
2.2.1.
Notification to its Reliability Coordinator, to
include current and projected conditions
when experiencing a Capacity Emergency or
Energy Emergency;
2.2.2
Requesting an Energy Emergency Alert, per
Attachment 1;
2.2.3.
Managing generating resources in its
Balancing Authority Area to address:
2.2.3.1. capability and availability;
2.2.3.2. fuel supply and inventory concerns;
2.2.3.3. fuel switching capabilities; and
2.2.3.4. environmental constraints.
2.2.4.
Public appeals for voluntary Load
reductions;
2.2.5.
Requests to government agencies to
implement their programs to achieve
necessary energy reductions;
2.2.6.
Reduction of internal utility energy use;
2.2.7.
Use of Interruptible Load, curtailable Load
and demand response;
Mapping Document

23

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-002-3.1, Capacity and Energy Emergencies
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

2.2.8.

2.2.9.

Provisions for operator-controlled manual
Load shedding that minimizes the overlap
with automatic Load shedding and are
capable of being implemented in a
timeframe adequate for mitigating the
Emergency; and
Reliability impacts of extreme weather
conditions.

R5. Each Reliability Coordinator that receives an
Emergency notification from a Transmission Operator or
Balancing Authority within its Reliability Coordinator
Area shall notify, within 30 minutes from the time of
receiving notification, other Balancing Authorities and
Transmission Operators in its Reliability Coordinator
Area, and neighboring Reliability Coordinators.
[Violation Risk Factor: High] [Time Horizon: Real-Time
Operations]
To have a TOP or BA contact other TOPs and BAs takes
them away from the Emergency at hand, plus they do
not have a wide-area view. The RC can give an indication

Mapping Document

24

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-002-3.1, Capacity and Energy Emergencies
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

of impact and make high-level determinations. The RC
has the wide-area overview and can quickly determine
impacts of neighboring TOPs, BAs and RCs. The RC is to
make contact within 30 minutes of notification. From
there, IRO-005, IRO-006 and IRO-007 would address the
specific actions to be taken.
R4. A Balancing Authority anticipating an operating
capacity or energy emergency shall perform all actions
necessary including bringing on all available generation,
postponing equipment maintenance, scheduling
interchange purchases in advance, and being prepared
to reduce firm load.

Mapping Document

Translated to EOP011-1, Emergency
Operations.

EOP-011-1, R2
R2.
Each Balancing Authority shall develop, maintain,
and implement a Reliability Coordinator-reviewed
Operating Plan(s) to mitigate Capacity Emergencies and
Energy Emergencies within its Balancing Authority Area.
The Operating Plan(s) shall include the following, as
applicable: [Violation Risk Factor: High] [Time Horizon:
Real-Time Operations, Operations Planning, Long-term
Planning]
2.1. Roles and responsibilities for activating the
Operating Plan(s);
2.2. Processes to prepare for and mitigate
Emergencies including:

25

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-002-3.1, Capacity and Energy Emergencies
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

2.2.1.

Notification to its Reliability Coordinator, to
include current and projected conditions
when experiencing a Capacity Emergency or
Energy Emergency;
2.2.2
Requesting an Energy Emergency Alert, per
Attachment 1;
2.2.3.
Managing generating resources in its
Balancing Authority Area to address:
2.2.3.1. capability and availability;
2.2.3.2. fuel supply and inventory concerns;
2.2.3.3. fuel switching capabilities; and
2.2.3.4. environmental constraints.
2.2.4.
Public appeals for voluntary Load
reductions;
2.2.5.
Requests to government agencies to
implement their programs to achieve
necessary energy reductions;
2.2.6.
Reduction of internal utility energy use;
2.2.7.
Use of Interruptible Load, curtailable Load
and demand response;
2.2.8.
Provisions for operator-controlled manual
Load shedding that minimizes the overlap
Mapping Document

26

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-002-3.1, Capacity and Energy Emergencies
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

2.2.9.

R5. A deficient Balancing Authority shall only use the
assistance provided by the Interconnection’s frequency
bias for the time needed to implement corrective
actions. The Balancing Authority shall not unilaterally
adjust generation in an attempt to return
interconnection frequency to normal beyond that
supplied through frequency bias action and Interchange
Schedule changes. Such unilateral adjustment may
overload transmission facilities.

EOP-002-3.1, R5
maps to BAL-003-1,
R1, R2, R3, and R4.

with automatic Load shedding and are
capable of being implemented in a
timeframe adequate for mitigating the
Emergency; and
Reliability impacts of extreme weather
conditions.

BAL-003-1, R1
R1. Each Frequency Response Sharing Group (FRSG) or
Balancing Authority that is not a member of a FRSG shall
achieve an annual Frequency Response Measure (FRM)
(as calculated and reported in accordance with
Attachment A) that is equal to or more negative than its
Frequency Response Obligation (FRO) to ensure that
sufficient Frequency Response is provided by each FRSG
or BA that is not a member of a FRSG to maintain
Interconnection Frequency Response equal to or more
negative than the Interconnection Frequency Response
Obligation.
BAL-003-1, R2

Mapping Document

27

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-002-3.1, Capacity and Energy Emergencies
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

R2. Each Balancing Authority that is a member of a
multiple Balancing Authority Interconnection and is not
receiving Overlap Regulation Service and uses a fixed
Frequency Bias Setting shall implement the Frequency
Bias Setting determined in accordance with Attachment
A, as validated by the ERO, into its Area Control Error
(ACE) calculation during the implementation period
specified by the ERO and shall use this Frequency Bias
Setting until directed to change by the ERO.
BAL-003-1, R3
R3. Each Balancing Authority that is a member of a
multiple Balancing Authority Interconnection and is not
receiving Overlap Regulation Service and is utilizing a
variable Frequency Bias Setting shall maintain a
Frequency Bias Setting that is: (1.1) Less than zero at all
times, and (1.2) Equal to or more negative than its
Frequency Response Obligation when Frequency varies
from 60 [Hertz] Hz by more than +/- 0.036 Hz.
BAL-003-1, R4

Mapping Document

28

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-002-3.1, Capacity and Energy Emergencies
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

R4. Each Balancing Authority that is performing Overlap
Regulation Service shall modify its Frequency Bias
Setting in its ACE calculation, in order to represent the
Frequency Bias Setting for the combined Balancing
Authority area, to be equivalent to either:
• the sum of the Frequency Bias Settings as shown
on FRS Form 1 and FRS Form 2 for the participating
Balancing Authorities as validated by the ERO, or
• the Frequency Bias Setting shown on FRS Form 1
and FRS Form 2 for the entirety of the participating
Balancing Authorities’ areas.
R6. If the Balancing Authority cannot comply with the
Control Performance and Disturbance
Control Standards, then it shall immediately implement
remedies to do so. These remedies
include, but are not limited to:
R6.1. Loading all available generating capacity.
R6.2. Deploying all available operating reserve.
R6.3. Interrupting interruptible load and exports.

Mapping Document

Translated to EOP011-1, Emergency
Operations.

EOP-011-1, R2
R2.
Each Balancing Authority shall develop, maintain,
and implement a Reliability Coordinator-reviewed
Operating Plan(s) to mitigate Capacity Emergencies and
Energy Emergencies within its Balancing Authority Area.
The Operating Plan(s) shall include the following, as
applicable: [Violation Risk Factor: High] [Time Horizon:
Real-Time Operations, Operations Planning, Long-term
Planning]

29

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-002-3.1, Capacity and Energy Emergencies
Requirement in Approved Standard

R6.4. Requesting emergency assistance from other
Balancing Authorities.
R6.5. Declaring an Energy Emergency through its
Reliability Coordinator; and
R6.6. Reducing load, through procedures such as
public appeals, voltage reductions,
curtailing interruptible loads and firm loads.

Mapping Document

Translation to
New Standard or
Other Action

Comments

2.1. Roles and responsibilities for activating the
Operating Plan(s);
2.2. Processes to prepare for and mitigate
Emergencies including:
2.2.1.
Notification to its Reliability Coordinator, to
include current and projected conditions
when experiencing a Capacity Emergency or
Energy Emergency;
2.2.2
Requesting an Energy Emergency Alert, per
Attachment 1;
2.2.3.
Managing generating resources in its
Balancing Authority Area to address:
2.2.3.1. capability and availability;
2.2.3.2. fuel supply and inventory concerns;
2.2.3.3. fuel switching capabilities; and
2.2.3.4. environmental constraints.
2.2.4.
Public appeals for voluntary Load
reductions;
2.2.5.
Requests to government agencies to
implement their programs to achieve
necessary energy reductions;
2.2.6.
Reduction of internal utility energy use;

30

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-002-3.1, Capacity and Energy Emergencies
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

2.2.7.
2.2.8.

2.2.9.
R7. Once the Balancing Authority has exhausted the
steps listed in Requirement 6, or if these steps
cannot be completed in sufficient time to resolve the
emergency condition, the Balancing
Authority shall:
R7.1. Manually shed firm load without delay to
return its ACE to zero; and
R7.2. Request the Reliability Coordinator to
declare an Energy Emergency Alert in
accordance with Attachment 1-EOP-002 “Energy
Emergency Alerts.”
Mapping Document

Translated to EOP011-1, Emergency
Operations.

Use of Interruptible Load, curtailable Load
and demand response;
Provisions for operator-controlled manual
Load shedding that minimizes the overlap
with automatic Load shedding and are
capable of being implemented in a
timeframe adequate for mitigating the
Emergency; and
Reliability impacts of extreme weather
conditions.

EOP-011-1, R2
R2.
Each Balancing Authority shall develop, maintain,
and implement a Reliability Coordinator-reviewed
Operating Plan(s) to mitigate Capacity Emergencies and
Energy Emergencies within its Balancing Authority Area.
The Operating Plan(s) shall include the following, as
applicable: [Violation Risk Factor: High] [Time Horizon:
Real-Time Operations, Operations Planning, Long-term
Planning]
2.1. Roles and responsibilities for activating the
Operating Plan(s);

31

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-002-3.1, Capacity and Energy Emergencies
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

2.2. Processes to prepare for and mitigate
Emergencies including:
2.2.1.
Notification to its Reliability Coordinator, to
include current and projected conditions
when experiencing a Capacity Emergency or
Energy Emergency;
2.2.2
Requesting an Energy Emergency Alert, per
Attachment 1;
2.2.3.
Managing generating resources in its
Balancing Authority Area to address:
2.2.3.1. capability and availability;
2.2.3.2. fuel supply and inventory concerns;
2.2.3.3. fuel switching capabilities; and
2.2.3.4. environmental constraints.
2.2.4.
Public appeals for voluntary Load
reductions;
2.2.5.
Requests to government agencies to
implement their programs to achieve
necessary energy reductions;
2.2.6.
Reduction of internal utility energy use;
2.2.7.
Use of Interruptible Load, curtailable Load
and demand response;
Mapping Document

32

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-002-3.1, Capacity and Energy Emergencies
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

2.2.8.

2.2.9.

Provisions for operator-controlled manual
Load shedding that minimizes the overlap
with automatic Load shedding and are
capable of being implemented in a
timeframe adequate for mitigating the
Emergency; and
Reliability impacts of extreme weather
conditions.

R8. A Reliability Coordinator that has any Balancing
Authority within its Reliability Coordinator area
experiencing a potential or actual Energy Emergency
shall initiate an Energy Emergency Alert as detailed in
Attachment 1-EOP-002 “Energy Emergency Alerts.” The
Reliability Coordinator shall act to mitigate the
emergency condition, including a request for
emergency assistance if required.

Translated to EOP011-1, Emergency
Operations.

EOP-011-1, R6
R6. Each Reliability Coordinator that has a Balancing
Authority experiencing a potential or actual Energy
Emergency within its Reliability Coordinator Area shall
declare an Energy Emergency Alert, as detailed in
Attachment 1. [Violation Risk Factor: High] [Time
Horizon: Real-Time Operations]

R9. When a Transmission Service Provider expects to
elevate the transmission service priority of an
Interchange Transaction from Priority 6 (Network
Integration Transmission Service from Non-designated

Retired per P81 –
this is addressed in
NAESB tagging
specification.

LSEs have no Real-time reliability functionality with
respect to EEAs.
Requirement R9 was in place to allow for a Transmission
Service Provider to change the priority of a service

Mapping Document

33

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-002-3.1, Capacity and Energy Emergencies
Requirement in Approved Standard

Resources) to Priority 7 (Network Integration
transmission Service from designated Network
Resources) as permitted in its transmission tariff:
R9.1. The deficient Load-Serving Entity shall
request its Reliability Coordinator to
initiate an Energy Emergency Alert in
accordance with Attachment 1-EOP-002
“Energy Emergency Alerts.”
R9.2. The Reliability Coordinator shall submit the
report to NERC for posting on the NERC
Website, noting the expected total MW
that may have its transmission service
priority changed.
R9.3. The Reliability Coordinator shall use EEA 1
to forecast the change of the priority of
transmission service of an Interchange
Transaction on the system from Priority 6
to Priority 7.
R9.4. The Reliability Coordinator shall use EEA 2
to announce the change of the priority of
transmission service of an Interchange

Mapping Document

Translation to
New Standard or
Other Action

Comments

request, informing the Reliability Coordinator so that the
service would not be curtailed by a TLR; and since the
Tagging Specs did not allow profiles to be changed, this
was the only method to accomplish it. Under NAESB
WEQ Etag Spec v1811 R3.6.1.3, this has been modified
and now the TSP has the ability to change the
Transmission priority which, in turn, is reflected in the
IDC. This technology change allows for the deletion of
Requirement R9 in its entirety. Requirement R9 meets
with Criterion A of Paragraph 81 and should be retired.

34

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-002-3.1, Capacity and Energy Emergencies
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

Transaction on the system from Priority 6
to Priority 7.
Attachment 1
Translated to EOP2.6.4 Operating Reserves. Operating reserves
011-1, Attachment
are being utilized such that the Energy
1.
Deficient Entity is carrying reserves below the required
minimum or has initiated emergency assistance through
its operating reserve sharing program.

Attachment 1EEA 2 – Load management procedures in
effect
• An energy deficient BA is still able to maintain
minimum Contingency Reserve requirements.
Using Contingency Reserves (which is a subset of
Operating Reserves) puts a BA closer to the operating
edge. The drafting team felt that the point where a BA
can no longer maintain this important Contingency
Reserves margin is a most serious condition and puts the
BA into a position where they are very close to shedding
Load (“imminent or in progress”). The drafting team felt
that this warrants categorization at the highest level of
EEA.
The previous language in EOP-002-3.1, EEA 2 used
“Operating Reserve,” which is an all-inclusive term,
including all reserves (including Contingency Reserves).
Many Operating Reserves are used continuously, every
hour of every day. Total Operating Reserve requirements

Mapping Document

35

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-002-3.1, Capacity and Energy Emergencies
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

are kind of nebulous since they do not have a specific
hard minimum value. Contingency Reserves are used far
less frequently. Because of the confusion over this issue,
evidenced by the comments received, the drafting team
thought that using minimum Contingency Reserve in the
language would eliminate some of the confusion. This is
a different approach but the drafting team believes this
is a good approach and was supported by several
commenters.

Mapping Document

36

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-003-2, Load Shedding Plans
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

R1. After taking all other remedial steps, a Transmission
Operator or Balancing Authority operating with
insufficient generation or transmission capacity shall
shed customer load rather than risk an uncontrolled
failure of components or cascading outages of the
Interconnection.

Translated to EOP011-1, Emergency
Operations.

EOP-011-1, R1
R1. Each Transmission Operator shall develop,
maintain, and implement a Reliability Coordinatorreviewed Operating Plan(s) to mitigate operating
Emergencies in its Transmission Operator Area. The
Operating Plan(s) shall include the following, as
applicable: [Violation Risk Factor: High] [Time
Horizon: Real-Time Operations, Operations
Planning, Long-term Planning]
1.1. Roles and responsibilities for activating the
Operating Plan(s);
1.2. Processes to prepare for and mitigate Emergencies
including:
1.2.1. Notification to its Reliability Coordinator, to
include current and projected conditions, when
experiencing an operating Emergency;
1.2.2. Cancellation or recall of Transmission and
generation outages;
1.2.3. Transmission system reconfiguration;
1.2.4. Redispatch of generation request;

Mapping Document

37

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-003-2, Load Shedding Plans
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

1.2.5. Provisions for operator-controlled manual
Load shedding that minimizes the overlap with
automatic Load shedding and are capable of
being implemented in a timeframe adequate
for mitigating the Emergency; and
1.2.6. Reliability impacts of extreme weather
conditions; and
EOP-011-1, R2
R2.
Each Balancing Authority shall develop, maintain,
and implement a Reliability Coordinator-reviewed
Operating Plan(s) to mitigate Capacity Emergencies and
Energy Emergencies within its Balancing Authority Area.
The Operating Plan(s) shall include the following, as
applicable: [Violation Risk Factor: High] [Time Horizon:
Real-Time Operations, Operations Planning, Long-term
Planning]
2.1. Roles and responsibilities for activating the
Operating Plan(s);
2.2. Processes to prepare for and mitigate Emergencies
including:

Mapping Document

38

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-003-2, Load Shedding Plans
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

2.2.1.

Notification to its Reliability Coordinator, to
include current and projected conditions
when experiencing a Capacity Emergency or
Energy Emergency;
2.2.2
Requesting an Energy Emergency Alert, per
Attachment 1;
2.2.3.
Managing generating resources in its
Balancing Authority Area to address:
2.2.3.1. capability and availability;
2.2.3.2. fuel supply and inventory concerns;
2.2.3.3. fuel switching capabilities; and
2.2.3.4. environmental constraints.
2.2.4.
Public appeals for voluntary Load
reductions;
2.2.5.
Requests to government agencies to
implement their programs to achieve
necessary energy reductions;
2.2.6.
Reduction of internal utility energy use;
2.2.7.
Use of Interruptible Load, curtailable Load
and demand response;
2.2.8.
Provisions for operator-controlled manual
Load shedding that minimizes the overlap
Mapping Document

39

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-003-2, Load Shedding Plans
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

2.2.9.
R2. Each Transmission Operator shall establish plans for
automatic load shedding for undervoltage conditions if
the Transmission Operator or its associated
Transmission Planner(s) or Planning Coordinator(s)
determine that an under-voltage load shedding scheme
is required.

Mapping Document

EOP-003-2, R2 maps
to PRC-010-1, R1.

Applicability is
changed to the PC
or TP because the
PC or TP is
responsible for the
program design.

with automatic Load shedding and are
capable of being implemented in a
timeframe adequate for mitigating the
Emergency; and
Reliability impacts of extreme weather
conditions.

Proposed Language in PRC-010-1:
R1. Each Planning Coordinator or Transmission Planner
that is developing a UVLS Program shall evaluate its
effectiveness and subsequently provide the UVLS
Program’s specifications and implementation schedule
to the UVLS entities responsible for implementing the
UVLS program. The evaluation shall include, but is not
limited to, studies and analyses that show: [Violation
Risk Factor: High] [Time Horizon: Long‐term
Planning]
1.1. The implementation of the UVLS Program resolves
the identified undervoltage issues that led to its
development and design.

40

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-003-2, Load Shedding Plans
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

1.2. The UVLS Program is integrated through
coordination with generator voltage ride-through
capabilities and other protection and control systems,
including, but not limited to, transmission line
protection, autoreclosing, Remedial Action Schemes, and
other undervoltage-based load shedding programs.
These tasks need to be performed in a planning horizon
in order to be implemented before any operational
issues arise. EOP-011-1 relates to Real-time operations
and the operations planning time horizon.
R3. Each Transmission Operator and Balancing
Authority shall coordinate load shedding plans,
excluding automatic under-frequency load shedding
plans, among other interconnected Transmission
Operators and Balancing Authorities.

Mapping Document

Translated to EOP011-1, Emergency
Operations.

EOP-011-1, R1
R1. Each Transmission Operator shall develop,
maintain, and implement a Reliability Coordinatorreviewed Operating Plan(s) to mitigate operating
Emergencies in its Transmission Operator Area. The
Operating Plan(s) shall include the following, as
applicable: [Violation Risk Factor: High] [Time
Horizon: Real-Time Operations, Operations
Planning, Long-term Planning]

41

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-003-2, Load Shedding Plans
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

1.1. Roles and responsibilities for activating the
Operating Plan(s);
1.2. Processes to prepare for and mitigate Emergencies
including:
1.2.1. Notification to its Reliability Coordinator, to
include current and projected conditions, when
experiencing an operating Emergency;
1.2.2. Cancellation or recall of Transmission and
generation outages;
1.2.3. Transmission system reconfiguration;
1.2.4. Redispatch of generation request;
1.2.5. Provisions for operator-controlled manual
Load shedding that minimizes the overlap with
automatic Load shedding and are capable of
being implemented in a timeframe adequate
for mitigating the Emergency; and
1.2.6. Reliability impacts of extreme weather
conditions; and
EOP-011-1, R2
R2.
Each Balancing Authority shall develop, maintain,
and implement a Reliability Coordinator-reviewed

Mapping Document

42

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-003-2, Load Shedding Plans
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

Operating Plan(s) to mitigate Capacity Emergencies and
Energy Emergencies within its Balancing Authority Area.
The Operating Plan(s) shall include the following, as
applicable: [Violation Risk Factor: High] [Time Horizon:
Real-Time Operations, Operations Planning, Long-term
Planning]
2.1. Roles and responsibilities for activating the
Operating Plan(s);
2.2. Processes to prepare for and mitigate
Emergencies including:
2.2.1.
Notification to its Reliability Coordinator, to
include current and projected conditions
when experiencing a Capacity Emergency or
Energy Emergency;
2.2.2
Requesting an Energy Emergency Alert, per
Attachment 1;
2.2.3.
Managing generating resources in its
Balancing Authority Area to address:
2.2.3.1. capability and availability;
2.2.3.2. fuel supply and inventory concerns;
2.2.3.3. fuel switching capabilities; and
2.2.3.4. environmental constraints.
Mapping Document

43

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-003-2, Load Shedding Plans
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

2.2.4.
2.2.5.
2.2.6.
2.2.7.
2.2.8.

2.2.9.
R4. A Transmission Operator shall consider one or more EOP-003-2, R4 maps
of these factors in designing an automatic under voltage to PRC-010-1, R1.
load shedding scheme: voltage level, rate of voltage
Applicability is
decay, or power flow levels.
changed to the PC
or TP because the
Mapping Document

Public appeals for voluntary Load
reductions;
Requests to government agencies to
implement their programs to achieve
necessary energy reductions;
Reduction of internal utility energy use;
Use of Interruptible Load, curtailable Load
and demand response;
Provisions for operator-controlled manual
Load shedding that minimizes the overlap
with automatic Load shedding and are
capable of being implemented in a
timeframe adequate for mitigating the
Emergency; and
Reliability impacts of extreme weather
conditions.

Proposed Language in PRC-010-1:
R1. Each Planning Coordinator or Transmission Planner
that is developing a UVLS Program shall evaluate its
effectiveness and subsequently provide the UVLS
Program’s specifications and implementation schedule

44

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-003-2, Load Shedding Plans
Requirement in Approved Standard

Translation to
New Standard or
Other Action

PC or TP is
responsible for the
program design.
EOP-003-2, R4 is
inherently
embedded in PRC010-1, R1, Part 1.1.
The specific items
noted are described
in PRC-010-1’s
Guidelines and
Technical Basis.

Comments

to the UVLS entities responsible for implementing the
UVLS program. The evaluation shall include, but is not
limited to, studies and analyses that show: [Violation
Risk Factor: High] [Time Horizon: Long‐term
Planning]
1.1. The implementation of the UVLS Program resolves
the identified undervoltage issues that led to its
development and design.
1.2. The UVLS Program is integrated through
coordination with generator voltage ride-through
capabilities and other protection and control systems,
including, but not limited to, transmission line
protection, autoreclosing, Remedial Action Schemes, and
other undervoltage-based load shedding programs.
These tasks need to be performed in a planning horizon
in order to be implemented before any operational
issues arise. EOP-011-1 relates to Real-time operations
and the operations planning time horizon.

Mapping Document

45

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-003-2, Load Shedding Plans
Requirement in Approved Standard

R5. A Transmission Operator or Balancing Authority
shall implement load shedding, excluding automatic
under-frequency load shedding, in steps established to
minimize the risk of further uncontrolled separation,
loss of generation, or system shutdown.

Mapping Document

Translation to
New Standard or
Other Action

Comments

Translated to EOP011-1, Emergency
Operations.

EOP-011-1, R1
R1. Each Transmission Operator shall develop,
maintain, and implement a Reliability Coordinatorreviewed Operating Plan(s) to mitigate operating
Emergencies in its Transmission Operator Area. The
Operating Plan(s) shall include the following, as
applicable: [Violation Risk Factor: High] [Time
Horizon: Real-Time Operations, Operations
Planning, Long-term Planning]
1.1. Roles and responsibilities for activating the
Operating Plan(s);
1.2. Processes to prepare for and mitigate Emergencies
including:
1.2.1. Notification to its Reliability Coordinator, to
include current and projected conditions, when
experiencing an operating Emergency;
1.2.2. Cancellation or recall of Transmission and
generation outages;
1.2.3. Transmission system reconfiguration;
1.2.4. Redispatch of generation request;

46

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-003-2, Load Shedding Plans
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

1.2.5. Provisions for operator-controlled manual
Load shedding that minimizes the overlap with
automatic Load shedding and are capable of
being implemented in a timeframe adequate
for mitigating the Emergency; and
1.2.6. Reliability impacts of extreme weather
conditions; and
EOP-011-1, R2
R2.
Each Balancing Authority shall develop, maintain,
and implement a Reliability Coordinator-reviewed
Operating Plan(s) to mitigate Capacity Emergencies and
Energy Emergencies within its Balancing Authority Area.
The Operating Plan(s) shall include the following, as
applicable: [Violation Risk Factor: High] [Time Horizon:
Real-Time Operations, Operations Planning, Long-term
Planning]
2.1. Roles and responsibilities for activating the
Operating Plan(s);
2.2. Processes to prepare for and mitigate Emergencies
including:

Mapping Document

47

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-003-2, Load Shedding Plans
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

2.2.1.

Notification to its Reliability Coordinator, to
include current and projected conditions
when experiencing a Capacity Emergency or
Energy Emergency;
2.2.2
Requesting an Energy Emergency Alert, per
Attachment 1;
2.2.3.
Managing generating resources in its
Balancing Authority Area to address:
2.2.3.1. capability and availability;
2.2.3.2. fuel supply and inventory concerns;
2.2.3.3. fuel switching capabilities; and
2.2.3.4. environmental constraints.
2.2.4.
Public appeals for voluntary Load
reductions;
2.2.5.
Requests to government agencies to
implement their programs to achieve
necessary energy reductions;
2.2.6.
Reduction of internal utility energy use;
2.2.7.
Use of Interruptible Load, curtailable Load
and demand response;
2.2.8.
Provisions for operator-controlled manual
Load shedding that minimizes the overlap
Mapping Document

48

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-003-2, Load Shedding Plans
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

2.2.9.
R6. After a Transmission Operator or Balancing
Authority Area separates from the Interconnection, if
there is insufficient generating capacity to restore
system frequency following automatic underfrequency
load shedding, the Transmission Operator or Balancing
Authority shall shed additional load.

Mapping Document

Translated to EOP011-1, Emergency
Operations.
Rehearing of FERC
Order No. 763,
Paragraph 11:
“Accordingly, we
grant clarification
that Order No. 763
did not preclude
some degree of
overlap between
automatic and
manual load

with automatic Load shedding and are
capable of being implemented in a
timeframe adequate for mitigating the
Emergency; and
Reliability impacts of extreme weather
conditions.

EOP-011-1, R1
R1. Each Transmission Operator shall develop,
maintain, and implement a Reliability Coordinatorreviewed Operating Plan(s) to mitigate operating
Emergencies in its Transmission Operator Area. The
Operating Plan(s) shall include the following, as
applicable: [Violation Risk Factor: High] [Time
Horizon: Real-Time Operations, Operations
Planning, Long-term Planning]
1.1. Roles and responsibilities for activating the
Operating Plan(s);
1.2. Processes to prepare for and mitigate Emergencies
including:

49

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-003-2, Load Shedding Plans
Requirement in Approved Standard

Translation to
New Standard or
Other Action

shedding programs,
provided there is
sufficient nonoverlapping load
available for
manual shedding to
achieve the
reliability objective
of EOP-003-2.”

Comments

1.2.1. Notification to its Reliability Coordinator, to
include current and projected conditions, when
experiencing an operating Emergency;
1.2.2. Cancellation or recall of Transmission and
generation outages;
1.2.3. Transmission system reconfiguration;
1.2.4. Redispatch of generation request;
1.2.5. Provisions for operator-controlled manual
Load shedding that minimizes the overlap with
automatic Load shedding and are capable of
being implemented in a timeframe adequate
for mitigating the Emergency; and
1.2.6. Reliability impacts of extreme weather
conditions; and
EOP-011-1, R2
R2.
Each Balancing Authority shall develop, maintain,
and implement a Reliability Coordinator-reviewed
Operating Plan(s) to mitigate Capacity Emergencies and
Energy Emergencies within its Balancing Authority Area.
The Operating Plan(s) shall include the following, as
applicable: [Violation Risk Factor: High] [Time Horizon:

Mapping Document

50

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-003-2, Load Shedding Plans
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

Real-Time Operations, Operations Planning, Long-term
Planning]
2.1. Roles and responsibilities for activating the
Operating Plan(s);
2.2. Processes to prepare for and mitigate Emergencies
including:
2.2.1.
Notification to its Reliability Coordinator, to
include current and projected conditions
when experiencing a Capacity Emergency or
Energy Emergency;
2.2.2
Requesting an Energy Emergency Alert, per
Attachment 1;
2.2.3.
Managing generating resources in its
Balancing Authority Area to address:
2.2.3.1. capability and availability;
2.2.3.2. fuel supply and inventory concerns;
2.2.3.3. fuel switching capabilities; and
2.2.3.4. environmental constraints.
2.2.4.
Public appeals for voluntary Load
reductions;

Mapping Document

51

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-003-2, Load Shedding Plans
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

2.2.5.
2.2.6.
2.2.7.
2.2.8.

2.2.9.

Requests to government agencies to
implement their programs to achieve
necessary energy reductions;
Reduction of internal utility energy use;
Use of Interruptible Load, curtailable Load
and demand response;
Provisions for operator-controlled manual
Load shedding that minimizes the overlap
with automatic Load shedding and are
capable of being implemented in a
timeframe adequate for mitigating the
Emergency; and
Reliability impacts of extreme weather
conditions.

Rehearing of FERC Order No. 763, Paragraph 11:
“Accordingly, we grant clarification that Order No. 763
did not preclude some degree of overlap between
automatic and manual load shedding programs,
provided there is sufficient non-overlapping load
available for manual shedding to achieve the reliability
objective of EOP-003-2.”

Mapping Document

52

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-003-2, Load Shedding Plans
Requirement in Approved Standard

Translation to
New Standard or
Other Action

R7. The Transmission Operator shall coordinate
automatic undervoltage load shedding throughout their
areas with tripping of shunt capacitors, and other
automatic actions that will occur under abnormal
voltage, or power flow conditions.

EOP-003-2, R7
maps to PRC-010-1,
R1.
Applicability is
changed to the PC
or TP because the
PC or TP is
responsible for the
program design.
EOP-003-2, R7 is
inherently
embedded in PRC010-1, R1, Part 1.2.
The specific items
noted are described
in PRC-010-1’s
Guidelines and
Technical Basis.

Mapping Document

Comments

Proposed Language in PRC-010-1:
R1. Each Planning Coordinator or Transmission Planner
that is developing a UVLS Program shall evaluate its
effectiveness and subsequently provide the UVLS
Program’s specifications and implementation schedule
to the UVLS entities responsible for implementing the
UVLS program. The evaluation shall include, but is not
limited to, studies and analyses that show: [Violation
Risk Factor: High] [Time Horizon: Long‐term
Planning]
1.1. The implementation of the UVLS Program resolves
the identified undervoltage issues that led to its
development and design.
1.2. The UVLS Program is integrated through
coordination with generator voltage ride-through
capabilities and other protection and control systems,
including, but not limited to, transmission line
protection, autoreclosing, Remedial Action Schemes, and
other undervoltage-based load shedding programs.

53

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-003-2, Load Shedding Plans
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

These tasks need to be performed in a planning horizon
in order to be implemented before any operational
issues arise. EOP-011-1 relates to Real-time operations
and the operations planning time horizon.
R8. Each Transmission Operator or Balancing Authority
shall have plans for operator controlled manual load
shedding to respond to real-time emergencies. The
Transmission Operator or Balancing Authority shall be
capable of implementing the load shedding in a
timeframe adequate for responding to the emergency.

Mapping Document

Translated to EOP011-1, Emergency
Operations.

EOP-011-1, R1
R1. Each Transmission Operator shall develop,
maintain, and implement a Reliability Coordinatorreviewed Operating Plan(s) to mitigate operating
Emergencies in its Transmission Operator Area. The
Operating Plan(s) shall include the following, as
applicable: [Violation Risk Factor: High] [Time
Horizon: Real-Time Operations, Operations
Planning, Long-term Planning]
1.1. Roles and responsibilities for activating the
Operating Plan(s);
1.2. Processes to prepare for and mitigate Emergencies
including:

54

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-003-2, Load Shedding Plans
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

1.2.1. Notification to its Reliability Coordinator, to
include current and projected conditions, when
experiencing an operating Emergency;
1.2.2. Cancellation or recall of Transmission and
generation outages;
1.2.3. Transmission system reconfiguration;
1.2.4. Redispatch of generation request;
1.2.5. Provisions for operator-controlled manual
Load shedding that minimizes the overlap with
automatic Load shedding and are capable of
being implemented in a timeframe adequate
for mitigating the Emergency; and
1.2.6. Reliability impacts of extreme weather
conditions; and
EOP-011-1, R2
R2.
Each Balancing Authority shall develop, maintain,
and implement a Reliability Coordinator-reviewed
Operating Plan(s) to mitigate Capacity Emergencies and
Energy Emergencies within its Balancing Authority Area.
The Operating Plan(s) shall include the following, as
applicable: [Violation Risk Factor: High] [Time Horizon:

Mapping Document

55

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-003-2, Load Shedding Plans
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

Real-Time Operations, Operations Planning, Long-term
Planning]
2.1. Roles and responsibilities for activating the
Operating Plan(s);
2.2. Processes to prepare for and mitigate
Emergencies including:
2.2.1.
Notification to its Reliability Coordinator, to
include current and projected conditions
when experiencing a Capacity Emergency or
Energy Emergency;
2.2.2
Requesting an Energy Emergency Alert, per
Attachment 1;
2.2.3.
Managing generating resources in its
Balancing Authority Area to address:
2.2.3.1. capability and availability;
2.2.3.2. fuel supply and inventory concerns;
2.2.3.3. fuel switching capabilities; and
2.2.3.4. environmental constraints.
2.2.4.
Public appeals for voluntary Load
reductions;

Mapping Document

56

Project 2008-12 - Coordinate Interchange Standards

Standard: EOP-003-2, Load Shedding Plans
Requirement in Approved Standard

Translation to
New Standard or
Other Action

Comments

2.2.5.
2.2.6.
2.2.7.
2.2.8.

2.2.9.

Mapping Document

Requests to government agencies to
implement their programs to achieve
necessary energy reductions;
Reduction of internal utility energy use;
Use of Interruptible Load, curtailable Load
and demand response;
Provisions for operator-controlled manual
Load shedding that minimizes the overlap
with automatic Load shedding and are
capable of being implemented in a
timeframe adequate for mitigating the
Emergency; and
Reliability impacts of extreme weather
conditions.

57

Exhibit K
Standard Drafting Team Roster for NERC Standards Development Project 2010-14.1

Project 2010-14.1 Phase 1 of Balancing Authority Reliabilitybased Controls: Reserves Standards Drafting Team Roster

1

Name
Glenn Stephens

Title
Manager – System
Planning
Consultant

Company
Santee Cooper

2

Tom Siegrist

3

Gerry Beckerle

Ameren

Howard Illian

Senior Transmission
Operations Supervisor
President

4
5

David Lemmons

Senior Consultant

Xcel Energy

6

Clyde Loutan

Senior Advisor

California ISO

7

LeRoy Patterson

Trainer

Grant County Public Utility District #2

8

Mark Prosperi-Porta

System Control Manger

BC Hydro

9

Tom Pruitt

Principal Engineer

Duke Energy

10

Jerry Rust

President

NWPP

Stone Mattheis Xenopoulos & Brew, P.C.

Energy Mark

Contact
843.761.8000 x 4482
[email protected]
678.520.6954
[email protected]
314.554.6413
[email protected]
847.910.9510
[email protected]
303.628.2813
[email protected]
916.608.5917
[email protected]
509) 754-7205
[email protected]
604.455.1783
[email protected]
704.382.4676
[email protected]
503.445.1074

Name

Title

Company

Contact

11

Stephen Swan

MISO

317.249.5075
[email protected]

12

Darrel Richardson

NERC

13

Andrew C. Wills

Senior Manager –
Generation Dispatch and
Balancing
Senior Standards
Developer
Associate Counsel

609.613.1848
[email protected]
202-400-3021
[email protected]

[email protected]

Project 2010-14.1 Phase 1 BARC – Reserves
Drafting Team Roster

NERC

2