NERC Petition for BAL-001-2

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 RELIABILITY STANDARD
BAL-001-2—REAL POWER BALANCING CONTROL PERFORMANCE

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
Stacey Tyrewala
Senior Counsel
North American Electric Reliability Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099 – facsimile
[email protected]
[email protected]
[email protected]
Counsel for the North American Electric
Reliability Corporation

April 2, 2014

TABLE OF CONTENTS
I. EXECUTIVE SUMMARY .................................................................................................... 2
II. NOTICES AND COMMUNICATIONS ................................................................................ 4
III. BACKGROUND .................................................................................................................... 4
A.
B.
C.

REGULATORY FRAMEWORK .................................................................................... 4
NERC RELIABILITY STANDARDS DEVELOPMENT PROCEDURE ..................... 5
HISTORY OF PROJECT 2010-14.1: PHASE 1 OF BALANCING AUTHORITY
RELIABILITY-BASED CONTROLS: RESERVES ..................................................... 6

IV. JUSTIFICATION FOR APPROVAL..................................................................................... 6
A.

BAL-001-2 – REAL POWER BALANCING CONTROL PERFORMANCE ............... 7
1.
2.
3.

B.
V.

Procedural History ........................................................................................................ 7
Proposed Definitions .................................................................................................... 7
Requirement-by-Requirement Justification................................................................ 11
ENFORCEABILITY OF PROPOSED RELIABILITY STANDARD BAL-001-2 ...... 13

CONCLUSION ..................................................................................................................... 14

Exhibit A

Proposed Reliability Standard BAL-001-2

Exhibit B

Implementation Plan for Proposed Reliability Standard BAL-001-2

Exhibit C

Order No. 672 Criteria

Exhibit D

Mapping Document

Exhibit E

BAL-001-2 – Real Power Balancing Control Performance Standard Background
Document

Exhibit F

Analysis of Violation Risk Factors and Violation Security Levels

Exhibit G

Summary of Development History and Complete Record of Development

Exhibit H

Standard Drafting Team Roster for Project 2010-14.1

i

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 RELIABILITY STANDARD
BAL-001-2—REAL POWER BALANCING CONTROL PERFORMANCE
Pursuant to Section 215(d)(1) of the Federal Power Act (“FPA”) 1 and Section 39.5 2 of the
Federal Energy Regulatory Commission’s (“FERC” or “Commission”) regulations, the North
American Electric Reliability Corporation (“NERC”) 3 hereby submits proposed Reliability
Standard BAL-001-2—Real Power Balancing Control Performance for Commission approval. 4
NERC requests that the Commission approve proposed Reliability Standard BAL-001-2, and
associated definitions (“Regulation Reserve Sharing Group,” “Reserve Sharing Group ACE,”
“Reporting ACE” and “Interconnection”) (Exhibit A) and find that the proposed Reliability
Standard and definitions are just, reasonable, not unduly discriminatory or preferential, and in the
public interest. 5 NERC also requests approval of the associated implementation plan (Exhibit
B), Violation Risk Factors (“VRFs”) and Violation Severity Levels (“VSLs”) (Exhibit F), and
retirement of Reliability Standard BAL-001-1 as detailed in this petition.

1

16 U.S.C. § 824o (2006).
18 C.F.R. § 39.5 (2013).
3
The Commission certified NERC as the electric reliability organization (“ERO”) in accordance with
Section 215 of the FPA on July 20, 2006. N. Am. Elec. Reliability Corp., 116 FERC ¶ 61,062 (2006).
4
The BAL-001 Reliability Standard is also commonly referred to as “Control Performance Standard 1” or
“CPS1.”
5
Unless otherwise designated, all capitalized terms shall have the meaning set forth in the Glossary of Terms
Used in NERC Reliability Standards, available at http://www.nerc.com/files/Glossary_of_Terms.pdf
2

1

As required by Section 39.5(a) 6 of the Commission’s regulations, this petition presents
the technical basis and purpose of proposed Reliability Standard and definitions, a summary of
the development history (Exhibit G), and a demonstration that the proposed Reliability Standard
meets the criteria identified by the Commission in Order No. 672 7 (Exhibit C). Proposed
Reliability Standard BAL-001-2 was approved by the NERC Board of Trustees on August 15,
2013.
I.

EXECUTIVE SUMMARY
The purpose of proposed Reliability Standard BAL-001-2 is to maintain Interconnection

frequency within predefined frequency limits. The reliable operation of an electric power system
depends on careful management of the balance between generation and load to ensure that
system frequency is maintained within narrow bounds around a scheduled value. The proposed
Reliability Standard improves reliability by adding a frequency component to the measurement
of a Balancing Authority’s Area Control Error (“ACE”) and allows for the formation of
“Regulation Reserve Sharing Groups.” Furthermore, the proposed BAL-001-2 Reliability
Standard and accompanying definitions, include the benefits of the Automatic Time Error
Correction (“ATEC”) equation in the WECC-specific regional variance in Reliability Standard
BAL-001-1. 8

6

18 C.F.R. § 39.5(a) (2013).
The Commission specified in Order No. 672 certain general factors it would consider when assessing
whether a particular Reliability Standard is just and reasonable. See Rules Concerning Certification of the Electric
Reliability Organization; and Procedures for the Establishment, Approval, and Enforcement of Electric Reliability
Standards, Order No. 672, FERC Stats. & Regs. ¶ 31,204, at P 262, 321-37, order on reh’g, Order No. 672-A,
FERC Stats. & Regs. ¶ 31,212 (2006).
8
The currently-effective BAL-001-1 Reliability Standard includes a WECC regional variance which has
been incorporated into the continent-wide proposed BAL-001-2 Reliability Standard through the definition of
“Reporting ACE,” as explained herein. This incorporation is consistent with Commission precedent, as the
Commission has noted, “The Commission seeks as much uniformity as possible in the proposed Reliability
Standards across the interconnected Bulk-Power System of the North American continent.” Order No. 672 at P 41.
7

2

Balancing Authorities are responsible for generation-demand-interchange balance in the
Balancing Authority Area and contribute to Interconnection frequency in Real-time. ACE is 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
ATEC, if operating in the ATEC mode. 9 The proposed Reliability Standard defines “Balancing
Authority ACE Limit” (“BAAL”) and requires a Balancing Authority to balance its resources
and demand in Real-time so that its clock-minute average of its ACE does not exceed its BAAL
for more than 30 consecutive clock-minutes.
The proposed Reliability Standard consists of two Requirements and two Attachments,
which set forth the mathematical equations that support Requirements R1 and R2 and the
accompanying Measures. Requirement R1 is intended to measure how well a Balancing
Authority is able to control its generation and load management programs, as measured by its
ACE, to support its Interconnection’s frequency over a rolling one-year period. Requirement R2
is intended to enhance the reliability of each Interconnection by maintaining frequency within
predefined limits under all conditions. Collectively, these Requirements and Attachments
support the reliability of the Bulk-Power System.
NERC requests an effective date of the first day of the first calendar quarter that is twelve
months after the date of Commission approval. 10 As explained below, NERC requests that the
Commission approve the proposed BAL-001-2 Reliability Standard and definitions as just and
reasonable.

9

ATEC is only applicable to Balancing Authorities in the Western Interconnection.
The proposed implementation period will allow entities to make any software adjustments that may be
required to perform the BAAL calculations.

10

3

II.

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

following: 11
Charles A. Berardesco*
Senior Vice President and General Counsel
Holly A. Hawkins*
Associate General Counsel
Stacey Tyrewala*
Senior Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099 – facsimile
[email protected]
[email protected]
[email protected]

III.

Mark G. Lauby
Vice President and Director of Standards
Valerie Agnew
Director of Standards Development
North American Electric Reliability
Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-2560
(404) 446-2595 – facsimile
[email protected]
[email protected]

BACKGROUND
A.

Regulatory Framework

By enacting the Energy Policy Act of 2005, 12 Congress entrusted the Commission with
the duties of approving and enforcing rules to ensure the reliability of the Nation’s Bulk-Power
System, and with the duties of certifying an ERO that would be charged with developing and
enforcing mandatory Reliability Standards, subject to Commission approval. Section 215(b)(1) 13
of the FPA states that all users, owners, and operators of the Bulk-Power System in the United
States will be subject to Commission-approved Reliability Standards. Section 215(d)(5) 14 of the
FPA authorizes the Commission to order the ERO to submit a new or modified Reliability

11

Persons to be included on the Commission’s service list are identified by an asterisk. NERC respectfully
requests a waiver of Rule 203 of the Commission’s regulations, 18 C.F.R. § 385.203 (2013), to allow the inclusion
of more than two persons on the service list in this proceeding.
12
16 U.S.C. § 824o (2006).
13
Id. § 824(b)(1).
14
Id. § 824o(d)(5).

4

Standard. Section 39.5(a) 15 of the Commission’s regulations requires the ERO to file with the
Commission for its approval each Reliability Standard that the ERO proposes should become
mandatory and enforceable in the United States, and each modification to a Reliability Standard
that the ERO proposes should be made effective.
The Commission has the regulatory responsibility to approve Reliability Standards that
protect the reliability of the Bulk-Power System and to ensure that such Reliability Standards are
just, reasonable, not unduly discriminatory or preferential, and in the public interest. Pursuant to
Section 215(d)(2) of the FPA 16 and Section 39.5(c) 17 of the Commission’s regulations, the
Commission will give due weight to the technical expertise of the ERO with respect to the
content of a Reliability Standard.
B.

NERC Reliability Standards Development Procedure

The proposed Reliability Standards were developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development process. 18 NERC
develops Reliability Standards in accordance with Section 300 (Reliability Standards
Development) of its Rules of Procedure and the NERC Standard Processes Manual. 19 In its ERO
Certification Order, the Commission found that NERC’s proposed rules provide for reasonable

15

18 C.F.R. § 39.5(a) (2012).
16 U.S.C. § 824o(d)(2).
17
18 C.F.R. § 39.5(c)(1).
18
Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the
Establishment, Approval, and Enforcement of Electric Reliability Standards, Order No. 672 at P 334, FERC Stats. &
Regs. ¶ 31,204, order on reh’g, Order No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006) (“Further, in considering
whether a proposed Reliability Standard meets the legal standard of review, we will entertain comments about
whether the ERO implemented its Commission-approved Reliability Standard development process for the
development of the particular proposed Reliability Standard in a proper manner, especially whether the process was
open and fair. However, we caution that we will not be sympathetic to arguments by interested parties that choose,
for whatever reason, not to participate in the ERO’s Reliability Standard development process if it is conducted in
good faith in accordance with the procedures approved by FERC.”).
19
The NERC Rules of Procedure are available at http://www.nerc.com/AboutNERC/Pages/Rules-ofProcedure.aspx. The NERC Standard Processes Manual is available at
http://www.nerc.com/comm/SC/Documents/Appendix_3A_StandardsProcessesManual.pdf.
16

5

notice and opportunity for public comment, due process, openness, and a balance of interests in
developing Reliability Standards and thus satisfies certain of the criteria for approving Reliability
Standards. The development process is open to any person or entity with a legitimate interest in
the reliability of the Bulk-Power System. NERC considers the comments of all stakeholders, and
a vote of stakeholders and the NERC Board of Trustees is required to approve a Reliability
Standard before the Reliability Standard is submitted to the Commission for approval.
C.

History of Project 2010-14.1: Phase 1 of Balancing Authority ReliabilityBased Controls: Reserves

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 (commonly referred to as “BARC”) 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. 20 A field trial was approved by the NERC Standards Committee and
Operating Committee and is ongoing. The results of the field trial thus far support the proposed
Reliability Standard and a report is currently in development.
IV.

JUSTIFICATION FOR APPROVAL
The purpose of proposed Reliability Standard BAL-001-2 is to maintain Interconnection

frequency within predefined frequency limits. As discussed in detail in Exhibit C, proposed
Reliability Standard BAL-001-2 satisfies the Commission’s criteria in Order No. 672 and is just,
reasonable, not unduly discriminatory or preferential, and in the public interest.

20

The BAL-002 Reliability Standard, which addresses Contingency Reserve for recovery from a balancing
contingency event, is part of this consolidated project and is currently in development. The proposed BAL-001-2
Reliability Standard is not directly linked to the content of the BAL-002-2 Reliability Standard and can be approved
separately.

6

A.

BAL-001-2 – REAL POWER BALANCING CONTROL PERFORMANCE

Provided below is the following: (1) the procedural history of the BAL-001 Reliability
Standard; (2) an explanation of the proposed definitions; and (3) and an explanation of the
proposed BAL-001-2 Reliability Standard on a requirement-by-requirement basis.
1.

Procedural History

BAL-001-0 was approved by the Commission in Order No. 693. 21 An interpretation to
BAL-001-0 was accepted by the Commission in Order No. 713. 22 The Commission approved
errata changes to BAL-001-0 via unpublished letter order on May 13, 2009 in Docket No. RD092-000. Reliability Standard BAL-001-1 was accepted by the Commission via unpublished letter
order on October 16, 2013. 23
2.

Proposed Definitions

NERC proposes four definitions for inclusion in the Glossary of Terms Used in NERC
Reliability Standards. Provided below is the text of each proposed definition and an explanation
of the need for these definitions.
•

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.

The proposed definition “Regulation Reserve Sharing Group” is necessary to acknowledge
that entities may form contractual arrangements in order to maintain enough Regulating Reserve.

21

Order No. 693 at P 308.
Modification of Interchange and Transmission Loading Relief Reliability Standards; and Electric
Reliability Organization Interpretation of Specific Requirements of Four Reliability Standards, Order No. 713, 124
FERC ¶ 61,071 (2008).
23
N. Am. Elec. Reliability Corp., Docket No. RD13-11-000 (October 16, 2013)(unpublished letter order).
22

7

This proposed definition is similar in concept to the Commission-approved terms “Reserve
Sharing Group” and “Frequency Response Sharing Group.” 24
•

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
(or equivalent as calculated at such time of measurement) of the Balancing Authorities
participating in the Regulation Reserve Sharing Group at the time of measurement.

The proposed definition of “Reserve Sharing Group Reporting ACE” facilitates the
demonstration of compliance with the BAL-001 Reliability Standard by Regulating Reserve
Sharing Groups. This allows for the formation of a virtual Balancing Authority Area while
allowing each individual entity to maintain their political boundaries.
•

Reporting ACE: The scan rate values of a Balancing Authority’s Area Control Error
(ACE) measured in MW, which includes the difference between the Balancing
Authority’s Net Actual Interchange and its Net Scheduled Interchange, plus its Frequency
Bias obligation, plus any known meter error. In the Western Interconnection, Reporting
ACE includes Automatic Time Error Correction (ATEC).
Reporting ACE is calculated as follows:
Reporting ACE = (NIA − NIS) − 10B (FA − FS) − IME
Reporting ACE is calculated in the Western Interconnection as follows:
Reporting ACE = (NIA − NIS) − 10B (FA − FS) − IME + IATEC
Where:
NIA (Actual Net Interchange) 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 (Scheduled Net Interchange) is the algebraic sum of all scheduled megawatt
transfers, including Dynamic Schedules, with adjacent Balancing Authorities, and taking
into account the effects of schedule ramps. Balancing Authorities directly connected via
asynchronous ties to another Interconnection may include or exclude megawatt transfers
on those Tie Lines in their scheduled Interchange, provided they are implemented in the
same manner for Net Interchange Actual.

24

See Order No. 693 at P 320 (“A reserve sharing group, however, as an independent organization, is able to
determine on its own as a commercial matter whether any penalties related to non-compliance should be
reapportioned among the members of the group.”); Frequency Response and Frequency Response Bias Setting
Reliability Standard, Order No. 794, 146 FERC ¶ 61,024 (2014).

8

B (Frequency Bias Setting) is the Frequency Bias Setting (in negative MW/0.1 Hz) for
the Balancing Authority.
10 is the constant factor that converts the Frequency Bias Setting units to MW/Hz.
FA (Actual Frequency) is the measured frequency in Hz.
FS (Scheduled Frequency) is 60.0 Hz, except during a time correction.
IME (Interchange Meter Error) is the meter error correction factor and represents the
difference between the integrated hourly average of the net interchange actual (NIA) and
the cumulative hourly net interchange energy measurement (in megawatt-hours).
IATEC (Automatic Time Error Correction) is the addition of a component to the ACE
equation for the Western Interconnection that modifies the control point for the purpose
of continuously paying back Primary Inadvertent Interchange to correct accumulated time
error. Automatic Time Error Correction is only applicable in the Western
Interconnection.
on/off peak

IATEC

= PII

accum

(1 − Y )* H

when operating in Automatic Time Error Correction control mode.

IATEC shall be zero when operating in any other AGC mode.
•

Y = B / BS.

•

H = Number of hours used to payback Primary Inadvertent Interchange energy. The
value of H is set to 3.

•

BS = Frequency Bias for the Interconnection (MW / 0.1 Hz).

•

Primary Inadvertent Interchange (PIIhourly) is (1-Y) * (IIactual - B * ΔTE/6)

•

IIactual is the hourly Inadvertent Interchange for the last hour.

•

ΔTE is the hourly change in system Time Error as distributed by the Interconnection
Time Monitor. Where:
ΔTE = TEend hour – TEbegin hour – TDadj – (t)*(TEoffset)

•

TDadj is the Reliability Coordinator adjustment for differences with Interconnection
Time Monitor control center clocks.

•

t is the number of minutes of Manual Time Error Correction that occurred during the
hour.

•

TEoffset is 0.000 or +0.020 or -0.020.

•

PIIaccum is the Balancing Authority’s accumulated PIIhourly in MWh. An On-Peak and
Off-Peak accumulation accounting is required.
Where:
on/off peak

PII

accum

= last period’s

9

on/off peak

PII

accum

+ PIIhourly

All NERC Interconnections with multiple Balancing Authorities operate using the
principles of Tie-line Bias (TLB) Control and require the use of an ACE equation similar to
the Reporting ACE defined above. Any modification(s) to this specified Reporting ACE
equation that is(are) implemented for all BAs on an Interconnection and is(are) consistent
with the following four principles will provide a valid alternative Reporting ACE equation
consistent with the measures included in this standard.
1. All portions of the Interconnection are included in one area or another so that the
sum of all area generation, loads and losses is the same as total system generation,
load and losses.
2. The algebraic sum of all area Net Interchange Schedules and all Net Interchange
actual values is equal to zero at all times.
3. The use of a common Scheduled Frequency FS for all areas at all times.
4. The absence of metering or computational errors. (The inclusion and use of the
IME term to account for known metering or computational errors.)

The proposed definition of “Reporting ACE” incorporates the equations in currentlyeffective Reliability Standard BAL-001-1 into the proposed definition. This proposed definition
also incorporates the ATEC equation in the WECC-specific regional variance in Reliability
Standard BAL-001-1.
•

Interconnection: When capitalized, any one of the four major electric system networks
in North America: Eastern, Western, ERCOT and Quebec.

The defined term “Interconnection” is used throughout the body of NERC Reliability
Standards and the proposed revision to this definition corrects the currently-effective definition,
to include the Quebec Interconnection. 25 The definition of “interconnection” was approved by
the Commission in Order No. 693. 26 The proposed revisions to this term are consistent with
NERC’s international role as the Electric Reliability Organization, pursuant to Section 215 of the
Federal Power Act.

25

The currently-effective definition of “Interconnection” is “When capitalized, any one of the three major
electric system networks in North America: Eastern, Western, and ERCOT.”
26
Order No. 693 at P 1898.

10

3.

Requirement-by-Requirement Justification

Proposed Reliability Standard BAL-001-2 consists of two Requirements and is applicable
to Balancing Authorities and Regulation Reserve Sharing Groups (a proposed defined term, as
explained herein). Provided below is an explanation of each of the Requirements of the
proposed Reliability Standard.
BAL-001-2, Requirement R1
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.

Requirement R1 of the BAL-001 Reliability Standard is commonly referred to as Control
Performance Standard 1 (“CPS1”) and this terminology is maintained in the proposed Reliability
Standard for historical continuity. Proposed Requirement R1 is a restatement of the BAL-001-1
Requirement R1 with the equation and explanation of the individual components moved to an
attachment, Attachment 1 - Equations Supporting Requirement R1 and Measure M1. The
proposed revisions to Requirement R1 are administratively efficient and clarify the intent of the
Requirement.
Proposed Requirement R1 is intended to measure how well a Balancing Authority is able
to control its generation and load management programs, as measured by its ACE, to support its
Interconnection’s frequency over a rolling one-year period. While the language of Requirement
R1 has been modified, the underlying performance aspect of the Requirement is unchanged.
Therefore, the Commission should approve the proposed revisions to Requirement R1.
BAL-001-2, Requirement R2
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
11

than 30 consecutive clock-minutes, calculated in accordance with Attachment 2, for the
applicable Interconnection in which the Balancing Authority operates.
Proposed Requirement R2 is a new requirement intended to replace the currentlyeffective BAL-001-1 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.
Attachment 2 sets forth the mathematical equations that support Requirement R2 and Measure
M2.
The Balancing Authority ACE Limits (“BAAL”) are unique for each Balancing
Authority and provide dynamic limits for its ACE value limit as a function of its Interconnection
frequency. 27 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 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 proposed Requirement R2 provides
each Balancing Authority a dynamic ACE limit that is a function of Interconnection frequency.
In summary, the proposed 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

27
BAAL was derived based on reliability studies and analysis which defined a Frequency Trigger Limit
bound measured in Hz. The Frequency Trigger Limit is equal to Scheduled Frequency, plus or minus three times an
Interconnection’s Epsilon 1 value. Epsilon 1 is the root mean square 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 Frequency Trigger Limit. When all
Balancing Authorities are within their BAAL (high and low), the Interconnection frequency will be within its
Frequency Trigger Limits.

12

individual Balancing Authority’s ACE or Interconnection frequency deviates into a region that
contributes too much risk to the Interconnection. This proposed Requirement replaces and
improves upon the current Requirement R2 and improves reliability by maintaining frequency
within predefined limits under all conditions.
B.

Enforceability of Proposed Reliability Standard BAL-001-2

The proposed Reliability Standard includes Violation Risk Factors (“VRFs”) and
Violation Severity Levels (“VSLs”). The VSLs provide guidance on the way that NERC will
enforce the Requirements of the proposed Reliability Standard. The VRFs are one of several
elements used to determine an appropriate sanction when the associated Requirement is violated.
The VRFs assess the impact to reliability of violating a specific Requirement. The VRFs and
VSLs for the proposed Reliability Standards comport with NERC and Commission guidelines
related to their assignment. For a detailed review of the VRFs, the VSLs, and the analysis of
how the VRFs and VSLs were determined using these guidelines, please see Exhibit F.
The proposed Reliability Standard also includes Measures that support each Requirement
by clearly identifying what is required and how the Requirement will be enforced. These
Measures help ensure that the Requirements will be enforced in a clear, consistent, and nonpreferential manner and without prejudice to any party. 28

28

Order No. 672 at P 327 (“There should be a clear criterion or measure of whether an entity is in compliance
with a proposed Reliability Standard. It should contain or be accompanied by an objective measure of compliance
so that it can be enforced and so that enforcement can be applied in a consistent and non-preferential manner.”).

13

V.

CONCLUSION
For the reasons set forth above, NERC respectfully requests that the Commission:
•

approve the proposed Reliability Standard and associated elements included in Exhibit
A, effective as proposed herein;

•

approve the implementation plan included in Exhibit B; and

•

approve the retirement of Reliability Standard BAL-001-1, effective as proposed herein.
Respectfully submitted,
/s/ Stacey Tyrewala
Charles A. Berardesco
Senior Vice President and General Counsel
Holly A. Hawkins
Associate General Counsel
Stacey Tyrewala
Senior Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099 – facsimile
[email protected]
[email protected]
[email protected]
Counsel for the North American Electric
Reliability Corporation

Date: April 2, 2014

14

Exhibit A
Proposed Reliability Standard BAL-001-2

Standard BAL-001-2 – Real Power Balancing Control Performance
A. Introduction
1.

Title:

Real Power Balancing Control Performance

2.

Number:

BAL-001-2

3.

Purpose:

To control Interconnection frequency within defined limits.

4.

Applicability:
4.1. Balancing Authority
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.
4.1.2 A Balancing Authority that is a member of a Regulation 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 the governing rules for the Regulation Reserve Sharing
Group.
4.2. Regulation Reserve Sharing Group

5.

(Proposed) Effective Date:
5.1.

First day of the first calendar quarter that is twelve 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 twelve 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.

B. Requirements
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. [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 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.[Violation
Risk Factor: Medium] [Time Horizon: Real-time Operations]

C. Measures
M1. The Responsible Entity shall provide evidence, upon request, such as dated calculation
output from spreadsheets, system logs, software programs, or other evidence (either
in hard copy or electronic format) to demonstrate compliance with Requirement R1.
Page 1 of 9

Standard BAL-001-2 – Real Power Balancing Control Performance
M2. Each Balancing Authority shall provide evidence, upon request, such as dated
calculation output from spreadsheets, 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
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. 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 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. Data required for the calculation of
Regulation Reserve Sharing Group Reporting Ace, or 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 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
Compliance Audits
Self-Certifications
Spot Checking
Compliance Investigation
Self-Reporting
Complaints

Page 2 of 9

Standard BAL-001-2 – Real Power Balancing Control Performance
1.4. Additional Compliance Information
None.
2.

Violation Severity Levels
R
#

R1

R2

Lower VSL

Moderate VSL

High VSL

Severe VSL

The CPS 1 value
of the
Responsible
Entity, for the
preceding 12
consecutive
calendar month
period, 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 for 45
consecutive
clock-minutes
or less for the
applicable
Interconnection.

The CPS 1 value
of the
Responsible
Entity, for the
preceding 12
consecutive
calendar month
period, is less
than 95 percent,
but greater than
or equal to 90
percent for the
applicable
Interconnection.

The CPS 1 value
of the
Responsible
Entity, for the
preceding 12
consecutive
calendar month
period, is less
than 90 percent,
but greater than
or equal to 85
percent for the
applicable
Interconnection.

The CPS 1 value of the
Responsible Entity, for
the preceding 12
consecutive calendar
month period, is less
than 85 percent for the
applicable
Interconnection.

The Balancing
Authority
exceeded its
clock-minute
BAAL for greater
than 45
consecutive
clock minutes
but for 60
consecutive
clock-minutes
or less for the
applicable
Interconnection.

The Balancing
Authority
exceeded its
clock-minute
BAAL for greater
than 60
consecutive
clock minutes
but for 75
consecutive
clock-minutes
or less for the
applicable
Interconnection.

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

E. Regional Variances
None.
F. Associated Documents
BAL-001-2, Real Power Balancing Control Performance Standard Background Document

Page 3 of 9

Standard BAL-001-2 – 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

Inclusion of BAAL and WECC Variance and
exclusion of CPS2

1

December 19,
2012

Adopted by NERC Board of Trustees

2

August 15, 2013

Adopted by the NERC Board of Trustees

Revision

Page 4 of 9

Standard BAL-001-2 – 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 for the most recent preceding 12 consecutive calendar months,
divided by the square of the target frequency bound:
CF =

CF

12 - month

(ε1I ) 2

Where ε1I is the constant derived from a targeted frequency bound for each
Interconnection as follows:
•

Eastern Interconnection ε1I = 0.018 Hz

•

Western Interconnection ε1I = 0.0228 Hz

•

ERCOT Interconnection ε1I = 0.030 Hz

•

Quebec Interconnection ε1I = 0.021 Hz

The rating index CF12-month is derived from the most recent preceding 12 consecutive
calendar 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.
A clock-minute average is the average of the reporting Balancing Authority’s valid
measured variable (i.e., for Reporting ACE (RACE) and for Frequency Error) for each
sampling cycle during a given clock-minute.

 RACE


 − 10 B clock -minute

 ∑ RACE
sampling cycles in clock - minute


nsampling cycles in clock -minute
=
- 10B






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:

Page 5 of 9

Standard BAL-001-2 – Real Power Balancing Control Performance
 RACE

CFclock -minute = 
* ∆Fclock -minute 

 − 10 B  clock -minute

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).

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) 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

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

]

)(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

CF12-month =

∑ (CF
i =1

month -i

)(n(one-minute samples in month )−i )]

12

∑ [n
i =1

( one - minute samples in month)-i

]

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
Page 6 of 9

Standard BAL-001-2 – Real Power Balancing Control Performance
Settings with the Reporting ACE and Frequency Bias Settings of the Balancing Authority
receiving the Regulation Service.

Page 7 of 9

Standard BAL-001-2 – Real Power Balancing Control Performance
Attachment 2
Equations Supporting Requirement R2 and Measure M2
When actual frequency is equal to Scheduled Frequency, BAALHigh and BAALLow do not apply.
When actual frequency is less than Scheduled Frequency, BAALHigh does not apply, and
BAALLow is calculated as:
BAALLow = (− 10 Bi × (FTLLow − FS ))×

(FTLLow − FS )
(FA − FS )

When actual frequency is greater than Scheduled Frequency, BAALLow does not apply and
the BAALHigh is calculated as:
BAALHigh = (− 10 Bi × (FTLHigh − FS ))×

(FTL

High

− FS )

(FA − FS )

Where:
BAALLow 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
Bi is the Frequency Bias Setting for a Balancing Authority (expressed as MW/0.1 Hz)
FA is the measured frequency in Hz.
FS is the scheduled frequency in Hz.
FTLLow is the Low Frequency Trigger Limit (calculated as FS - 3ε1I Hz)
FTLHigh is the High Frequency Trigger Limit (calculated as FS + 3ε1I Hz)
Where ε1I is the constant derived from a targeted frequency bound for each
Interconnection as follows:
•

Eastern Interconnection ε1I = 0.018 Hz

•

Western Interconnection ε1I = 0.0228 Hz

•

ERCOT Interconnection ε1I = 0.030 Hz

•

Quebec Interconnection ε1I = 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

Page 8 of 9

Standard BAL-001-2 – Real Power Balancing Control Performance
data is available or valid, then that one-minute interval is excluded from the BAAL
calculation and the 30-minute clock would be reset to zero.
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 Overlap Regulation Service.

Page 9 of 9

Standard BAL‐001‐2 – 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. 
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. 
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 (or equivalent as 
calculated at such time of measurement) of the Balancing Authorities participating in the 
Regulation Reserve Sharing Group at the time of measurement. 
Reporting ACE:  The scan rate values of a Balancing Authority’s Area Control Error (ACE) 
measured in MW, which includes the difference between the Balancing Authority’s Net Actual 
Interchange and its Net Scheduled Interchange, plus its Frequency Bias obligation, plus any 
known meter error. In the Western Interconnection, Reporting ACE includes Automatic Time 
Error Correction (ATEC). 
Reporting ACE is calculated as follows: 

Reporting ACE = (NIA − NIS) − 10B (FA − FS) − IME 
Reporting ACE is calculated in the Western Interconnection as follows: 

Reporting ACE = (NIA − NIS) − 10B (FA − FS) − IME + IATEC 

Where: 
NIA (Actual Net Interchange) 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 (Scheduled Net Interchange) is the algebraic sum of all scheduled megawatt 
transfers, including Dynamic Schedules, with adjacent Balancing Authorities, and taking 
into account the effects of schedule ramps.  Balancing Authorities directly connected via 
asynchronous ties to another Interconnection may include or exclude 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.  

Standard BAL‐001‐2 – Real Power Balancing Control Performance 
FA (Actual Frequency) is the measured frequency in Hz.  
FS (Scheduled Frequency) is 60.0 Hz, except during a time correction. 
IME (Interchange Meter Error) is the meter error correction factor and represents the 
difference between the integrated hourly average of the net interchange actual (NIA) 
and the cumulative hourly net interchange energy measurement (in megawatt‐hours). 
IATEC (Automatic Time Error Correction) is the addition of a component to the ACE 
equation for the Western Interconnection that modifies the control point for the 
purpose of continuously paying back Primary Inadvertent Interchange to correct 
accumulated time error.  Automatic Time Error Correction is only applicable in the 
Western Interconnection. 
on/off peak

IATEC

 PII

accum

1  Y * H

 when operating in Automatic Time Error Correction control mode.  

 IATEC shall be zero when operating in any other AGC mode. 


Y = B / BS. 



H = Number of hours used to payback Primary Inadvertent Interchange energy. The 
value of H is set to 3. 



BS = Frequency Bias for the Interconnection (MW / 0.1 Hz). 



Primary Inadvertent Interchange (PIIhourly) is (1‐Y) * (IIactual ‐ B * ΔTE/6) 



IIactual is the hourly Inadvertent Interchange for the last hour. 



ΔTE is the hourly change in system Time Error as distributed by the Interconnection 
Time Monitor. Where: 

ΔTE = TEend hour – TEbegin hour – TDadj – (t)*(TEoffset) 



TDadj is the Reliability Coordinator adjustment for differences with Interconnection 
Time Monitor control center clocks. 



t is the number of minutes of Manual Time Error Correction that occurred during the 
hour. 



TEoffset is 0.000 or +0.020 or ‐0.020.   



PIIaccum is the Balancing Authority’s accumulated PIIhourly in MWh. An On‐Peak and 
Off‐Peak accumulation accounting is required. 
Where: 

PII

on/off peak
accum

 = last period’s 

on/off peak

PII

accum

 + PIIhourly 

All NERC Interconnections with multiple Balancing Authorities operate using the principles 
of Tie‐line Bias (TLB) Control and require the use of an ACE equation similar to the 

Standard BAL‐001‐2 – Real Power Balancing Control Performance 
Reporting ACE defined above.  Any modification(s) to this specified Reporting ACE 
equation that is(are) implemented for all BAs on an Interconnection and is(are) consistent 
with the following four principles will provide a valid alternative Reporting ACE equation 
consistent with the measures included in this standard. 
1. All portions of the Interconnection are included in one area or another so that 
the sum of all area generation, loads and losses is the same as total system 
generation, load and losses. 
2. The algebraic sum of all area Net Interchange Schedules and all Net Interchange 
actual values is equal to zero at all times. 
3. The use of a common Scheduled Frequency FS for all areas at all times. 
4. The absence of metering or computational errors.  (The inclusion and use of the 
IME term to account for known metering or computational errors.) 

Interconnection: When capitalized, any one of the four major electric system networks in North 
America: Eastern, Western, ERCOT and Quebec.

Exhibit B
Implementation Plan for Proposed Reliability Standard BAL-001-2

Implementation Plan
Project 2010-14.1 Balancing Authority Reliability-based Controls
- Reserves
Implementation Plan for BAL-001-2 – Real Power Balancing Control Performance
Approvals Required
BAL-001-2 – Real Power Balancing Control Performance
Prerequisite Approvals
None
Revisions to Glossary Terms
The following definitions shall become effective when BAL-001-2 becomes effective:
Regulation Reserve Sharing Group: A group whose members consist of two or more Balancing
Authorities that collectively maintain, allocate, and supply the Regulating Rreserve required for
all member Balancing Authorities to use in meeting applicable regulating standards.
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 (or equivalent as
calculated at such time of measurement) of the Balancing Authorities participating in the
Regulation Reserve Sharing Group at the time of measurement.
Reporting ACE: The scan rate values of a Balancing Authority’s Area Control Error (ACE)
measured in MW, which includes the difference between the Balancing Authority’s Net Actual
Interchange and its Net Scheduled Interchange, plus its Frequency Bias obligation, plus any
known meter error. In the Western Interconnection, Reporting ACE includes Automatic Time
Error Correction (ATEC).
Reporting ACE is calculated as follows:
Reporting ACE = (NIA − NIS) − 10B (FA − FS) − IME
Reporting ACE is calculated in the Western Interconnection as follows:
Reporting ACE = (NIA − NIS) − 10B (FA − FS) − IME + IATEC

Where:
NIA (Actual Net Interchange) 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 (Scheduled Net Interchange) is the algebraic sum of all scheduled megawatt
transfers, including Dynamic Schedules, with adjacent Balancing Authorities, and taking
into account the effects of schedule ramps. Balancing Authorities directly connected via
asynchronous ties to another Interconnection may include or exclude 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.
FS (Scheduled Frequency) is 60.0 Hz, except during a time correction.
IME (Interchange Meter Error) is the meter error correction factor and represents the
difference between the integrated hourly average of the net interchange actual (NIA)
and the cumulative hourly net Interchange energy measurement (in megawatt-hours).
IATEC (Automatic Time Error Correction) is the addition of a component to the ACE
equation for the Western Interconnection that modifies the control point for the
purpose of continuously paying back Primary Inadvertent Interchange to correct
accumulated time error. Automatic Time Error Correction is only applicable in the
Western Interconnection.
on/off peak

IATEC

= PII

accum

(1 − Y )* H

when operating in Automatic Time Error Correction control mode.

IATEC shall be zero when operating in any other AGC mode.
•

Y = B / BS.

•

H = Number of hours used to payback Primary Inadvertent Interchange energy. The
value of H is set to 3.

•

BS = Frequency Bias for the Interconnection (MW / 0.1 Hz).

•

Primary Inadvertent Interchange (PIIhourly) is (1-Y) * (IIactual - B * ΔTE/6)

•

IIactual is the hourly Inadvertent Interchange for the last hour.

BAL-001-2 – Real Power Balancing Control Performance
July, 2013

2

•

ΔTE is the hourly change in system Time Error as distributed by the Interconnection
Time Monitor. Where:
ΔTE = TEend hour – TEbegin hour – TDadj – (t)*(TEoffset)

•

TDadj is the Reliability Coordinator adjustment for differences with Interconnection
Time Monitor control center clocks.

•

t is the number of minutes of Manual Time Error Correction that occurred during the
hour.

•

TEoffset is 0.000 or +0.020 or -0.020.

•

PIIaccum is the Balancing Authority’s accumulated PIIhourly in MWh. An On-Peak and
Off-Peak accumulation accounting is required.
Where:

PII

on/off peak
accum

= last period’s

on/off peak

PII

accum

+ PIIhourly

All NERC Interconnections with multiple Balancing Authorities operate using the principles
of Tie-line Bias (TLB) Control and require the use of an ACE equation similar to the Reporting
ACE defined above. Any modification(s) to this specified Reporting ACE equation that
is(are) implemented for all BAs on an Interconnection and is(are) consistent with the
following four principles will provide a valid alternative Reporting ACE equation consistent
with the measures included in this standard.
1. All portions of the Interconnection are included in one area or another so that the
sum of all area generation, loads and losses is the same as total system generation,
load and losses.
2. The algebraic sum of all area Net Interchange Schedules and all Net Interchange
actual values is equal to zero at all times.
3. The use of a common Scheduled Frequency FS for all areas at all times.
4. The absence of metering or computational errors. (The inclusion and use of the IME
term to account for known metering or computational errors.)
Interconnection: When capitalized, any one of the four major electric system networks in North
America: Eastern, Western, ERCOT and Quebec.
The existing definition of Interconnection should be retired at midnight of the day immediately prior to
the effective date of BAL-001-2, in the jurisdiction in which the new standard is becoming effective.

BAL-001-2 – Real Power Balancing Control Performance
July, 2013

3

The proposed revised definition for “Interconnection” is incorporated in the NERC approved standards,
detailed in Attachment 1 of this document.
Applicable Entities
Balancing Authority
Regulation Reserve Sharing Group
Applicable Facilities
N/A
Conforming Changes to Other Standards
None
Effective Dates
BAL-001-2 shall become effective as follows:
First day of the first calendar quarter that is twelve 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 twelve 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 twelve-month period for implementation of BAL-001-2 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-001-2 in the particular jurisdiction in which the new
standard is becoming effective.

BAL-001-2 – Real Power Balancing Control Performance
July, 2013

4

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
IRO-005-2a — Reliability Coordination — Current Day Operations

BAL-001-2 – Real Power Balancing Control Performance
July, 2013

5

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-001-2 – Real Power Balancing Control Performance
July, 2013

6

Exhibit C
Order No. 672 Criteria

Exhibit C
Order No. 672 Criteria
In Order No. 672, 1 the Commission identified a number of criteria it will use to analyze
Reliability Standards proposed for approval to ensure they are just, reasonable, not unduly
discriminatory or preferential, and in the public interest. The discussion below identifies these
factors and explains how the proposed Reliability Standard has met or exceeded the criteria:
1.

Proposed Reliability Standards must be designed to achieve a specified reliability
goal and must contain a technically sound means to achieve that goal. 2
The proposed Reliability Standard achieves the specific reliability goal of ensuring that

interconnection frequency is controlled within defined limits. The proposed Reliability Standard
consists of two Requirements and two Attachments, which set forth the mathematical equations
that support Requirements R1 and R2 and the accompanying Measures. Requirement R1 is
intended to measure how well a Balancing Authority is able to control its generation and load
management programs, as measured by its ACE, to support its Interconnection’s frequency over
a rolling one-year period. Requirement R2 is intended to enhance the reliability of each
Interconnection by maintaining frequency within predefined limits under all conditions.

1

Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the Establishment,
Approval, and Enforcement of Electric Reliability Standards, Order No. 672, FERC Stats. & Regs. ¶ 31,204, order
on reh’g, Order No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006).
2
Order No. 672 at P 321. The proposed Reliability Standard must address a reliability concern that falls within the
requirements of section 215 of the FPA. That is, it must provide for the reliable operation of Bulk-Power System
facilities. It may not extend beyond reliable operation of such facilities or apply to other facilities. Such facilities
include all those necessary for operating an interconnected electric energy transmission network, or any portion of
that network, including control systems. The proposed Reliability Standard may apply to any design of planned
additions or modifications of such facilities that is necessary to provide for reliable operation. It may also apply to
Cybersecurity protection.
Order No. 672 at P 324. The proposed Reliability Standard must be designed to achieve a specified reliability goal
and must contain a technically sound means to achieve this goal. Although any person may propose a topic for a
Reliability Standard to the ERO, in the ERO’s process, the specific proposed Reliability Standard should be
developed initially by persons within the electric power industry and community with a high level of technical
expertise and be based on sound technical and engineering criteria. It should be based on actual data and lessons
learned from past operating incidents, where appropriate. The process for ERO approval of a proposed Reliability
Standard should be fair and open to all interested persons.

Collectively, these Requirements and Attachments support the reliability of the Bulk-Power
System.
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 applies to Balancing Authorities and Regulation
Reserve Sharing Groups and is clear and unambiguous as to what is required and who is required
to comply, in accordance with Order No. 672. Section 4.1.1 clarifies that a Balancing Authority
receiving Overlap Regulation Service is not subject to Control Performance Standard 1 (CPS1)
or Balancing Authority ACE Limit (BAAL) compliance evaluation. Section 4.1.2 clarifies that a
Balancing Authority that is a member of a Regulation 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 the governing rules for the Regulation Reserve Sharing Group. The
requirements clearly state who is required to comply with the standard.
3.

A proposed Reliability Standard must include clear and understandable
consequences and a range of penalties (monetary and/or non-monetary) for a
violation. 4
The VRFs and VSLs for the proposed standard comport with NERC and Commission

guidelines related to their assignment. The assignment of the severity level for each VSL is
consistent with the corresponding Requirement and the VSLs should ensure uniformity and
consistency in the determination of penalties. The VSLs do not use any ambiguous terminology,

3

Order No. 672 at P 322. The proposed Reliability Standard may impose a requirement on any user, owner, or
operator of such facilities, but not on others.

Order No. 672 at P 325. The proposed Reliability Standard should be clear and unambiguous regarding what is
required and who is required to comply. Users, owners, and operators of the Bulk-Power System must know what
they are required to do to maintain reliability.
4
Order No. 672 at P 326. The possible consequences, including range of possible penalties, for violating a
proposed Reliability Standard should be clear and understandable by those who must comply.

2

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.

4.

A proposed Reliability Standard must identify clear and objective criterion or
measure for compliance, so that it can be enforced in a consistent and non
preferential manner. 5
The proposed Reliability Standard contains measures that support each requirement by

clearly identifying what is required and how the requirement will be enforced. These measures
help provide clarity regarding how the requirements will be enforced, and ensure that the
requirements will be enforced in a clear, consistent, and non-preferential manner and 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 its reliability goals effectively and efficiently

in accordance with Order No. 672. Proposed Requirement R1 is intended to measure how well a
Balancing Authority is able to control its generation and load management programs, as
measured by its ACE, to support its Interconnection’s frequency over a rolling one-year period.
While the language of Requirement R1 has been modified, the underlying performance aspect of
the Requirement is unchanged. The proposed Requirement R2 is intended to enhance the
reliability of each Interconnection by maintaining frequency within predefined limits under all

5

Order No. 672 at P 327. There should be a clear criterion or measure of whether an entity is in compliance with a
proposed Reliability Standard. It should contain or be accompanied by an objective measure of compliance so that it
can be enforced and so that enforcement can be applied in a consistent and non-preferential manner.
6
Order No. 672 at P 328. The proposed Reliability Standard does not necessarily have to reflect the optimal
method, or “best practice,” for achieving its reliability goal without regard to implementation cost or historical
regional infrastructure design. It should however achieve its reliability goal effectively and efficiently.

3

conditions. Attachment 2 sets forth the mathematical equations that support Requirement R2 and
Measure M2.
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 a significant improvement over the
previous version as described herein.
7.

Proposed Reliability Standards must be designed to apply throughout North
America to the maximum extent achievable with a single Reliability Standard while
not favoring one geographic area or regional model. It should take into account
regional variations in the organization and corporate structures of transmission
owners and operators, variations in generation fuel type and ownership patterns,
and regional variations in market design if these affect the proposed Reliability
Standard. 8
The proposed Reliability Standard applies throughout North America and does not favor

one geographic area or regional model. The proposed BAL-001-2 Reliability Standard and

7

Order No. 672 at P 329. The proposed Reliability Standard must not simply reflect a compromise in the ERO’s
Reliability Standard development process based on the least effective North American practice — the so-called
“lowest common denominator” — if such practice does not adequately protect Bulk-Power System reliability.
Although FERC will give due weight to the technical expertise of the ERO, we will not hesitate to remand a
proposed Reliability Standard if we are convinced it is not adequate to protect reliability.
Order No. 672 at P 330. A proposed Reliability Standard may take into account the size of the entity that must
comply with the Reliability Standard and the cost to those entities of implementing the proposed Reliability
Standard. However, the ERO should not propose a “lowest common denominator” Reliability Standard that would
achieve less than excellence in operating system reliability solely to protect against reasonable expenses for
supporting this vital national infrastructure. For example, a small owner or operator of the Bulk-Power System must
bear the cost of complying with each Reliability Standard that applies to it.
8
Order No. 672 at P 331. A proposed Reliability Standard should be designed to apply throughout the
interconnected North American Bulk-Power System, to the maximum extent this is achievable with a single
Reliability Standard. The proposed Reliability Standard should not be based on a single geographic or regional
model but should take into account geographic variations in grid characteristics, terrain, weather, and other such
factors; it should also take into account regional variations in the organizational and corporate structures of
transmission owners and operators, variations in generation fuel type and ownership patterns, and regional variations
in market design if these affect the proposed Reliability Standard.

4

accompanying definitions, include the benefits of the Automatic Time Error Correction
(“ATEC”) equation in the WECC-specific regional variance in Reliability Standard BAL-001-1.
The currently-effective BAL-001-1 Reliability Standard includes a WECC regional
variance which has been incorporated into the continent-wide proposed BAL-001-2 Reliability
Standard through the definition of “Reporting ACE,” as explained herein. This incorporation is
consistent with Commission precedent, as the Commission has noted, “The Commission seeks as
much uniformity as possible in the proposed Reliability Standards across the interconnected
Bulk-Power System of the North American continent.” Order No. 672 at P 41.
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 does not 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.

9

Order No. 672 at P 332. As directed by section 215 of the FPA, FERC itself will give special attention to the effect
of a proposed Reliability Standard on competition. The ERO should attempt to develop a proposed Reliability
Standard that has no undue negative effect on competition. Among other possible considerations, a proposed
Reliability Standard should not unreasonably restrict available transmission capability on the Bulk-Power System
beyond any restriction necessary for reliability and should not limit use of the Bulk-Power System in an unduly
preferential manner. It should not create an undue advantage for one competitor over another.
10
Order No. 672 at P 333. In considering whether a proposed Reliability Standard is just and reasonable, FERC
will consider also the timetable for implementation of the new requirements, including how the proposal balances
any urgency in the need to implement it against the reasonableness of the time allowed for those who must comply
to develop the necessary procedures, software, facilities, staffing or other relevant capability.

5

This will allow applicable entities adequate time to ensure compliance with the requirements.
The proposed effective dates are explained in the proposed Implementation Plan, attached as
Exhibit B.
10.

The Reliability Standard was developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development
process. 11
The proposed Reliability Standard was developed in accordance with NERC’s

Commission-approved, ANSI- accredited processes for developing and approving Reliability
Standards. Exhibit G includes a summary of the Reliability Standard development proceedings,
and details the processes followed to develop the standard.
These processes included, among other things, multiple comment periods, pre-ballot
review periods, and balloting periods. Additionally, all meetings of the drafting team were
properly noticed and open to the public. The initial and final ballots both achieved a quorum and
exceeded the required ballot pool approval levels.
11.

NERC must explain any balancing of vital public interests in the development of
proposed Reliability Standards.12
NERC has identified no competing public interests regarding the request for approval of

this proposed Reliability Standard. No comments were received that indicated the proposed
standard conflicts with other vital public interests.

11

Order No. 672 at P 334. Further, in considering whether a proposed Reliability Standard meets the legal standard
of review, we will entertain comments about whether the ERO implemented its Commission-approved Reliability
Standard development process for the development of the particular proposed Reliability Standard in a proper
manner, especially whether the process was open and fair. However, we caution that we will not be sympathetic to
arguments by interested parties that choose, for whatever reason, not to participate in the ERO’s Reliability Standard
development process if it is conducted in good faith in accordance with the procedures approved by FERC.
12
Order No. 672 at P 335. Finally, we understand that at times development of a proposed Reliability Standard
may require that a particular reliability goal must be balanced against other vital public interests, such as
environmental, social and other goals. We expect the ERO to explain any such balancing in its application for
approval of a proposed Reliability Standard.

6

12.

Proposed Reliability Standards must consider any other appropriate factors. 13
No other negative factors relevant to whether the proposed Reliability Standard is just

and reasonable were identified.

13

Order No. 672 at P 323. In considering whether a proposed Reliability Standard is just and reasonable, we will
consider the following general factors, as well as other factors that are appropriate for the particular Reliability
Standard proposed.

7

Exhibit D
Mapping Document

Project 2010-14.1 Balancing Authority Reliability-based
Controls - Reserves
BAL-001-2 Real Power Balancing Control Performance
Mapping Document
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

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

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-001-2 Real Power Balancing Control Performance
February, 2013

2

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

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
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.
R3. Each Balancing Authority providing
Overlap Regulation Service shall

BAL-001-2 Real Power Balancing Control Performance
February, 2013

This Requirement has been
moved into the BAL-001-2

Attachment 1
A Balancing Authority providing Overlap Regulation Service

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
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.
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).

BAL-001-2 Real Power Balancing Control Performance
February, 2013

This Requirement has been
moved into the BAL-001-2
Applicability Section.

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.

5

Exhibit E
BAL-001-2 Real Power Balancing Control Performance Standard Background Document

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:
 Lack of theoretical justification
 Large ACE treated the same as a small ACE, regardless of direction
 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, 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 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
Bias
ACE//Bias
puACE

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

Exhibit F
Analysis of Violation Risk Factors and Violation Security 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-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

VSLs for BAL-001-2 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.

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

BAL-001-2 Real Power Balancing Control Performance
VRF and VSL Assignments – February, 2013

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.

7

VSLs for BAL-001-2 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
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

R2.

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.

BAL-001-2 Real Power Balancing Control Performance
VRF and VSL Assignments – February, 2013

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.

8

Exhibit G
Summary of Development History and Complete Record of Development

Exhibit G - Summary of the Standard Development Proceedings and Record of
Development of Proposed Definition of Bulk Electric System

The development record for the proposed revisions to the BAL-001-2 Reliability Standard is
summarized below.
I.

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

“due weight” to the technical expertise of the ERO. 1 The technical expertise of the ERO is
derived from the standard drafting team. For this project, the standard drafting team consisted of
industry experts, all with a diverse set of experiences. A roster of the standard drafting team
members is included in Exhibit H.
II.

Standard Development History
A. Standard Authorization Request Development
The Standard Authorization Request (“SAR”) for revisions to the BAL-001 Reliability

Standard was originally posted as part of Project 2007-18 from May 15, 2007 to June 13, 2007.
There were 27 sets of comments, including comments from more than 60 different people
from more than 35 companies representing 9 of the 10 industry segments.
A revised SAR was posted from September 20, 2007 to October 9, 2007. There were 21
sets of comments, including comments from more than 80 different people from more than 40
companies representing 9 of the 10 industry segments. On July 28, 2010, Project 2007-18 –
Reliability-based Control, was merged with Project 2007-05 – Balancing Authority Controls,
creating Project 2010-14.1—Balancing Authority Reliability-based Controls: Reserves. Project
2010-14 was separated into two phases, with phase 1 moving into formal standards development

1

Section 215(d)(2) of the Federal Power Act; 16 U.S.C. §824(d)(2) (2006).

on July 13, 2011. Phase 1 consists of proposed revisions to BAL-001 and BAL-002; BAL-002 is
currently in development.
B. The First Posting – Formal Comment Period
The first draft of the BAL-001 Reliability Standard was posted for a formal comment
period from June 4, 2012 to July 3, 2012. There were 38 sets of comments, including comments
from approximately 85 companies representing 9 of the 10 industry segments.
Based on industry comments the drafting team made the following clarifying
modifications to the proposed standard and associated documents.
•
•
•
•
•
•

Created a definition for Regulation Reserve Sharing Group and Regulation Reserve
Sharing Group reporting ACE.
Removed the equation for calculating Reporting ACE from the attachment and added it
to the definition.
Modified the applicability section to provide additional clarity and remove any
ambiguity.
Made minor clarifying modifications to Requirement R1 and Requirement R2.
Made minor clarifying modifications to the VSLs for Requirement R1 and Requirement
R2.
Modified the Background Document to provide additional clarity.
C. The Second Posting – Formal Comment Period and Initial Ballot
The second draft of the BAL-001 Reliability Standard was posted for a formal 30-day

comment period from March 12, 2013 to April 25, 2013, with an initial ballot held from April
16, 2013 to April 25, 2013. The initial ballot achieved a 88.6% quorum, and an approval of
66.98%. The standard drafting team received 55 sets of comments, including comments from
approximately 100 companies representing 8 of the 10 industry segments. Several changes were
made to the draft of the BAL-001 Reliability Standard including:

2

•
•
•
•

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.
D. Third Posting - Final Ballot
The final ballot for the Reliability Standard was conducted from July 16, 2013 to July 25,

2013. The final ballot achieved a quorum of 92.31%, and an approval of 74.54%.
E. Board of Trustees Approval
Revisions to the BAL-001 Reliability Standard were approved by the NERC Board of
Trustees on August 15, 2013.

3

Project 2010‐14.1 Phase 1 of Balancing Authority Reliability‐based Controls: 
Reserves  
Status: 
BAL‐001‐2 was adopted by the NERC Board of Trustees on August 15, 2013 and will be filed with the 
appropriate regulatory agency. 

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.  
This project is intended to address the following:  
‐ 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.  
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.  

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.  
Draft 

Action 

Dates 

Results 

Consideration of 
Comments 

BAL‐002‐2 
Clean |Redline to 
Last Posting 
Implementation 
Plan 
Clean |Redline to 
Last Posting 

Additional Ballot 
and Non‐Binding 
Poll 

Updated Info>> 
Info>>  
Vote>> 

12/02/13 ‐ 
12/12/13 
(non‐binding poll 
extended one 
additional day) 
(closed) 

Summary>> 
Ballot 
Results>> 
Non‐Binding 
Poll Results>> 

Supporting 
Materials: 

Unofficial Comment 
Form (Word) 
Comment Period  

Background 
Document 
Clean |Redline to 
Last Posting 

Info>> 

10/28/13 ‐ 
12/11/13 

(closed) 

Mapping Document 
Clean |Redline to 
Last Posting 

Comments 
Received>> 

Submit 
Comments>> 

CR Form 1 
BAL‐002‐2 
Clean | Redline to 
Last Posting 

Additional Ballot 
Updated Info>> 

Implementation 
Plan 

Vote>> 

09/06/13 ‐ 
09/17/13 
(non‐binding poll 
extended one 
additional day) 
(closed) 

Clean | Redline to 
Last Posting 

Summary>> 
Ballot 
Results>> 
Non‐binding 
Poll Results>> 
Consideration of 
Comments>>

Supporting 
Materials: 

Comment Period 
Info>> 

Unofficial Comment 
Submit 
Form (Word) 
Comments>> 
Background 
Document 

08/02/13 ‐ 
09/17/13 
(closed) 

Comments 
Received>>  

Clean | Redline to 
Last Posting 
VRF/VSL Justification 

Mapping Document 
Clean | Redline to 
Last Posting 

CR Form 1 
BAL‐001‐2 
Clean (26) | Redline 
to Last Posting (27) 
Implementation 
Plan 
Clean (28) | Redline 
to Last Posting (29) 
Supporting 
Materials: 
Background 
Document 
Clean (30) | Redline 
to Last Posting (31) 

Final Ballot 
Info (36) 

07/16/13 ‐ 
07/25/13 

Vote>> 

(closed) 

Summary (37) 

Ballot Results 
(38) 

VRF/VSL Justification 
Clean (32) | Redline 
to Last Posting (33) 
Mapping Document 
Clean(34) | Redline 
to Last Posting (35) 
BAL‐001‐2 
Clean (10) 

Redline to Last 
Posting (11) 

Initial Ballots and 
Non‐binding Polls 
Info (19)  

04/16/13 ‐ 
04/25/13 

Vote>> 

(closed) 

Summary (21)  Consideration of 
Ballot Results:  Comments: 

BAL‐001‐2 (25) 

BAL‐002‐2 

BAL‐002‐2 

Implementation 
Plan  

Formal Comment 
Period 

Clean (12) 

Info (20) 

Redline to Last 
Posting (13) 

Submit 
Comments>> 

BAL‐002‐2 

BAL‐001‐2  

Clean  

BAL‐002‐2 

Redline to Last 
Posting 

BAL‐013‐1 

BAL‐001‐2 (22) 
BAL‐013‐1 
03/12/13 ‐ 
04/25/13 
(closed) 

BAL‐013‐1 
‐‐‐‐‐‐‐‐ 
Comments 
Received: 
BAL‐001‐2 (24) 

Clean | 

BAL‐002‐2 

Redline to Last 
Posting 

BAL‐013‐1 

BAL‐013‐1 
Clean |  
Redline to Last 
Posting 

Clean | 
Redline to Last 
Posting 
Supporting 
Materials: 
Unofficial Comment 
Forms (Word) 
BAL‐001‐2 (14) 
BAL‐002‐2 
BAL‐013‐1 
Background 
Documents: 

BAL‐001‐2 (23) 
BAL‐002‐2 

Implementation 
Plan 

Implementation 
Plan 

Non‐binding 
Poll Results: 

Join Ballot 
Pools>> 

03/12/13 ‐ 
04/10/13 

Join 

(closed) 

BAL‐001‐2 
Clean (15) |  
Redline to Last 
Posting (16) 
BAL‐002‐2 
Clean 
BAL‐013‐1 
Clean | Redline to 
Last Posting 
Mapping 
Documents 
BAL‐001‐2 (17) 
BAL‐002‐2 
VRF/VSL 
Justification 
BAL‐001‐2 (18) 
BAL‐002‐2 
BAL‐013‐1 

Draft 2  
BAL‐012‐1  
Clean | Redline to 
Last Posting  
Supporting 
Materials:  

Summary>> 

Initial Ballot and 
Non‐Binding Poll 
Updated Info>> 
Info>> 

Update 
1/4/2012 – 
1/14/2013 
(closed) 

Vote>> 

Formal Comment 
Unofficial Comment 
Period 
Form (Word) 
11/30/2012 – 
1/14/2013 
Info>> 
Background 
(closed) 
Document 
Submit 
Comments>> 

Ballot 
Results>> 

Non‐binding 
Poll Results>> 

Comments 
Received>>

Clean | Redline to 
Last Posting  
Implementation 
Plan 
Clean | Redline to 
Last Posting  

Join Ballot Pool  
Join>> 

11/30/2012 – 
1/3/2013 
(closed) 

Comments 
Received (9)  

Consideration of 
Comments>>(39) 

Comments 
Received>>  

VRF/VSL Justification  
Draft 1 
BAL‐001‐1  
Clean (1) 
Supporting 
Materials:  

Formal Comment 
Unofficial Comment  Period  
Form (Word) (2) 
Info (8) 
6/4/2012 ‐
7/3/2012 
BAL‐001‐0.1a (3) 
Submit 
Comments>> 
(closed) 
Background 
Document (4) 
Comment Form ‐ 
BAL‐001‐1  
Implementation 
Plan (5)  
Mapping Document 
(6) 
VRF/VSL Justification 
(7)  
Draft 1  
BAL‐002‐2  
Clean  

Supporting 
Materials:  
Unofficial Comment 
Form (Word)  

BAL‐002‐1  

Background 

Formal Comment 
Period  

6/4/2012 ‐
Info>>  
7/3/2012  

(closed) 
Submit 
Comments>>  
Comment Form ‐ 
BAL‐002‐2 

Document  

Implementation 
Plan  

Mapping Document  

Draft 1  
BAL‐012‐1  
Clean  

Supporting 
Materials:  
Unofficial Comment 
Form (Word)  

Background 
Document  

Implementation 
Plan  

Formal Comment 
Period  

6/4/2012 ‐ 
Info>>  
7/3/2012  

(closed) 
Submit 
Comments>>  
Comment Form ‐ 
BAL‐012‐1 

Comments 
Received>>  

Consideration of 
Comments>>  

Draft 1  
BAL‐013‐1  
Clean  

Supporting 
Materials:  
Unofficial Comment 
Form (Word)  

Background 
Document  

Implementation 
Plan  

Formal Comment 
Period  

6/4/2012 ‐
Info>>  
7/3/2012  

(closed) 
Submit 
Comments>>  
Comment Form ‐ 
BAL‐013‐1 

Comments 
Received>>  

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

(ε1I ) 2

where ε1 I is the constant derived from a targeted frequency bound for each
Interconnection as follows:
•

Eastern Interconnection ε1I = 0.018 Hz

•

Western Interconnection ε1I = 0.0228 Hz

•

ERCOT Interconnection ε1I = 0.030 Hz

•

Quebec Interconnection ε1I = 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 − NIS) − 10B (FA − FS) − NME
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  clock -minute

 ∑ ACEsampling cycles in clock -minute


nsampling cycles in clock -minute
=
- 10B






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:
 ACE 

CFclock -minute = 
* ∆Fclock -minute 

 − 10 B  clock -minute

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

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 ) 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

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

]

)(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

CF12-month =

∑ (CF
i =1

month -i

)(n(one-minute samples in month )−i )]

12

∑ [n
i =1

( one - minute samples in month)-i

]

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 × (FTLLow − 60)) ×

(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 = (− 10 Bi × (FTLHigh − 60))×

(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 60-3ε1I Hz)
FTLHigh is the High Frequency Trigger Limit (calculated as 60+3ε1I Hz)
Where ε1I is the constant derived from a targeted frequency bound for each
Interconnection as follows:
•

Eastern Interconnection ε1I = 0.018 Hz

•

Western Interconnection ε1I = 0.0228 Hz

•

ERCOT Interconnection ε1I = 0.030 Hz

•

Quebec Interconnection ε1I = 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 − 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 ε12 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.
 ACEi
AVG Period 
 ACE i 

 − 10 Bi
 * ∆F1  ≤∈12 or
AVG Period 
∈12
 − 10 Bi 1

The equation for ACE is:



 * ∆F1 

1

≤1

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

R2.

•

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 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 (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 ) ≤ 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 )

ε10 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, 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.
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: ε1 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  clock -minute

∆Fclock -minute =

 ∑ ACEsampling cycles in clock-minute


nsampling cycles in clock -minute
=
- 10B






∑ ∆F

sampling cycles in clock - minute

nsampling cycles in clock -minute

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

Page 2 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

 ACE 

CFclock -minute = 
* ∆Fclock -minute 

 − 10 B  clock -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

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

]

)(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

CF12-month =

∑ (CF
i =1

month -i

)(n(one-minute samples in month )−i )]

12

∑ [n
i =1

( one - minute samples in month)-i

]

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:



Violations month
CPS 2 = 1 −
 * 100
 (Total Periods month − Unavailable Periods month )
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.
Page 3 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
Violation clock-ten-minutes
= 0 if

∑ ACE
nsamples in 10-minutes

≤ 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%.
Page 4 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
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

ε1

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 ε1 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.

ε10

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

Retain the value of ε10 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.

Page 6 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 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
specific limit. This limit ε12 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.



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



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 ro l
P e r fo rm a n ce St a n d a rd
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:
•
•
•

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:
 Lack of theoretical justification
 Large ACE treated the same as a small ACE, regardless of direction
 Independent of Interconnection frequency

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

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
•

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-001-1 retains CPS1, but proposes a new measure BAAL. 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.
• 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

Project 2010-14.1 Balancing Authority Reliability-based
Controls - Reserves
BAL-001-1 Real Power Balancing Control Performance
Mapping Document
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
specific limit. This limit ε12 is a
constant derived from a targeted
frequency bound (separately
calculated for each

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

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-001-1 Real Power Balancing Control Performance
June 4, 2012

2

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.
• 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 ) ≤ L10
where:

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
The calculation equation for BAAL is located in Attachment 2 of
L10=1.65 Є10
BAL-001-1.
ε10 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
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.
R3. Each Balancing Authority providing
Overlap Regulation Service shall

BAL-001-1 Real Power Balancing Control Performance
June 4, 2012

This Requirement has been
moved into the BAL-001-1

Applicability Section 4.1.1 and Attachment 1
A Balancing Authority providing Overlap Regulation Service

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
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.
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).

BAL-001-1 Real Power Balancing Control Performance
June 4, 2012

This Requirement has been
moved into the BAL-001-1
Applicability Section and
Attachment 1.

Applicability Section 4.1.3 and Attachment 1
A Balancing Authority receiving Overlap Regulation Service is
not subject to CPS1 or BAAL compliance evaluation.

5

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
•
•
•
•
•
•
•
•
•
•
•
•

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:

•

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.

•

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-001-1 Real Power Balancing Control Performance
VRF and VSL Assignments – December, 2011

3

VRF for BAL-001-1, Requirement R2:

•

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.

•

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-001-1 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

VSLs for BAL-001-1 Requirem ent 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.

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

BAL-001-1 Real Power Balancing Control Performance
VRF and VSL Assignments – December, 2011

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.

7

VSLs for BAL-001-1 Requirem ent 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
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

R2.

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.

BAL-001-1 Real Power Balancing Control Performance
VRF and VSL Assignments – December, 2011

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.

8

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 − 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 − 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 ≤
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
Comment Form

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 ≤
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 − 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

Standard BAL‐001‐2 – 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 2010‐
14.1, Balancing Authority Reliability‐based Controls – Reserves) into formal standards 
development on July 13, 2011.  
8. The draft standard was posted for 30‐day formal industry comment period from June 4, 
2012 through July 3, 2012. 
Proposed Action Plan and Description of Current Draft: 
This is the second posting of the proposed new standard.  This proposed draft standard will be 
posted for a 45‐day formal comment period beginning on March 12, 2013 through April 25, 
2013.  

Future Development Plan: 
Anticipated Actions 
1. Second posting 

Anticipated Date 
March/April 2013 

2. Initial Ballot 

April 2013 

3. Recirculation Ballot 

October 2013 

4. NERC BOT adoption. 

November 2013 

BAL‐001‐2 
January 1, 2013 

Page 1 of 13 

Standard BAL‐001‐2 – 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. 
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. 
Reporting ACE:  The scan rate values of a Balancing Authority’s Area Control Error (ACE) 
measured in MW, which includes the difference between the Balancing Authority’s 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). 
Reporting ACE is calculated as follows: 

Reporting ACE = (NIA − NIS) − 10B (FA − FS) − IME + IATEC 

Where: 
NIA (Actual Net Interchange) 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 (Scheduled Net Interchange) is the algebraic sum of all scheduled megawatt 
transfers, including Dynamic Schedules, with adjacent Balancing Authorities, and taking 
into account the effects of schedule ramps.  Balancing Authorities directly connected via 
asynchronous ties to another Interconnection may include or exclude 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.  
BAL‐001‐2 
January 1, 2013 

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Standard BAL‐001‐2 – Real Power Balancing Control Performance 
FA (Actual Frequency) is the measured frequency in Hz.  
FS (Scheduled Frequency) is 60.0 Hz, except during a time correction. 
IME (Interchange Meter Error) is the meter error correction factor and represents the 
difference between the integrated hourly average of the net interchange actual (NIA) 
and the cumulative hourly net Interchange energy measurement (in megawatt‐hours). 
IATEC (Automatic Time Error Correction) is the addition of a component to the ACE 
equation that modifies the control point for the purpose of continuously paying back 
Primary Inadvertent Interchange to correct accumulated time error.  Automatic Time 
Error Correction is only applicable in the Western interconnection. 
on/off peak

IATEC

 PII

accum

1  Y * H

 when operating in Automatic Time Error Correction control mode.  

 IATEC shall be zero when operating in any other AGC mode. 


Y = B / BS. 



H = Number of Hours used to payback Primary Inadvertent Interchange energy. The 
value of H is set to 3. 



BS = Frequency Bias for the Interconnection (MW / 0.1 Hz). 



Primary Inadvertent Interchange (PIIhourly) is (1‐Y) * (IIactual ‐ B * ΔTE/6) 



IIactual is the hourly Inadvertent Interchange for the last hour. 



ΔTE is the hourly change in system Time Error as distributed by the Interconnection 
Time Monitor. Where: 

ΔTE = TEend hour – TEbegin hour – TDadj – (t)*(TEoffset) 



TDadj is the Reliability Coordinator adjustment for differences with Interconnection 
Time Monitor control center clocks. 



t is the number of minutes of Manual Time Error Correction that occurred during the 
hour. 



TEoffset is 0.000 or +0.020 or ‐0.020.   



PIIaccum is the Balancing Authority’s accumulated PIIhourly in MWh. An On‐Peak and 
Off‐Peak accumulation accounting is required. 
Where: 

PII

on/off peak
accum

 = last period’s 

on/off peak

PII

accum

 + PIIhourly 

All NERC Interconnections with multiple Balancing Authorities operate using the principles 
of Tie‐line Bias (TLB) Control and require the use of an ACE equation similar to the 
Reporting ACE defined above.  Any modification(s) to this specified Reporting ACE 
BAL‐001‐2 
January 1, 2013 

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Standard BAL‐001‐2 – Real Power Balancing Control Performance 
equation that is(are) implemented for all BAs on an interconnection and is(are) consistent 
with the following four principles will provide a valid alternative Reporting ACE equation 
consistent with the measures included in this standard. 
1. All portions of the interconnection are included in one area or another so that 
the sum of all area generation, loads and losses is the same as total system 
generation, load and losses. 
2. The algebraic sum of all area net interchange schedules and all net interchange 
actual values is equal to zero at all times. 
3. The use of a common scheduled frequency FS for all areas at all times. 
4. The absence of metering or computational errors.  (The inclusion and use of the 
IME term to account for known metering or computational errors.) 

Interconnection: When capitalized, any one of the four major electric system networks in North 
America: Eastern, Western, ERCOT and Quebec.

BAL‐001‐2 
January 1, 2013 

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Standard BAL‐001‐2 – Real Power Balancing Control Performance 
A. Introduction
1.

Title: 

Real Power Balancing Control Performance  

2.

Number: 

BAL‐001‐2 

3.

Purpose: 

To control Interconnection frequency within defined limits. 

4.

Applicability: 
4.1. Balancing Authority 
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. 
4.1.2 A Balancing Authority that is a member of a 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 

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.

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 12‐month 
period, evaluated monthly. [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 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] 

C. Measures 
M1. The Responsible Entity 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. 
BAL‐001‐2 
January 1, 2013 

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Standard BAL‐001‐2 – Real Power Balancing Control Performance 
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 
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. 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 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.  Data required for the calculation of 
Regulation Reserve Sharing Group Reporting Ace, or 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 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 
Compliance Audits 
Self‐Certifications 
Spot Checking 
Compliance Investigation 
Self‐Reporting 
Complaints 

BAL‐001‐2 
January 1, 2013 

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Standard BAL‐001‐2 – Real Power Balancing Control Performance 
1.4. Additional Compliance Information 
None. 
2.

Violation Severity Levels 
R
#

Lower VSL

R1  The CPS 1 value 
of the 
Responsible 
Entity, on a 
rolling 12‐
month basis, is 
less than 100 
percent but 
greater than or 
equal to 95 
percent for the 
applicable 
Interconnection. 
R2  The Balancing 
Authority 
exceeded its 
clock‐minute 
BAAL for more 
than 30 
consecutive 
clock minutes 
but for 45 
consecutive 
clock minutes or 
less. 

Moderate VSL

High VSL

Severe VSL

The CPS 1 value 
of the 
Responsible 
Entity, on a 
rolling 12‐
month 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 for 60 
consecutive 
clock minutes or 
less. 

The CPS 1 value 
of the 
Responsible 
Entity, on a 
rolling 12‐
month 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 for 75 
consecutive 
clock minutes or 
less. 

The CPS 1 value of the 
Responsible Entity, on a 
rolling 12‐month basis, 
is less than 85 percent 
for the applicable 
Interconnection. 

The Balancing Authority 
exceeded its clock‐
minute BAAL for greater 
than 75 consecutive 
clock‐minutes. 

E. Regional Variances 
None. 
F. Associated Documents 
BAL‐001‐2, Real Power Balancing Control Performance Standard Background Document 
Version History 
Version 
0 

BAL‐001‐2 
January 1, 2013 

Date 

Action 

Change Tracking 

February 8, 

BOT Approval 

New 

Page 7 of 13 

Standard BAL‐001‐2 – Real Power Balancing Control Performance 
2005 
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 

Inclusion of BAAL and WECC Variance and 
exclusion of CPS2 

Revision 

1 

BAL‐001‐2 
January 1, 2013 

Page 8 of 13 

Standard BAL‐001‐2 – 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 for the most recent consecutive 12‐calendar months, divided by 
the square of the target frequency bound: 
CF =

CF

12 ‐ month

(ε1I ) 2

Where ε1I is the constant derived from a targeted frequency bound for each 
Interconnection as follows:  


Eastern Interconnection ε1I = 0.018 Hz  



Western Interconnection ε1I = 0.0228 Hz  



ERCOT Interconnection ε1I = 0.030 Hz 



Quebec Interconnection ε1I = 0.021 Hz  

The rating index CF12‐month is derived from the most recent consecutive 12‐calendar 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. 
A clock‐minute average is the average of the reporting Balancing Authority’s valid 
measured variable (i.e., for Reporting ACE (RACE) and for Frequency Error) for each 
sampling cycle during a given clock minute. 

 RACE


  10 B  clock-minute

  RACE
sampling cycles in clock - minute


nsampling cycles in clock-minute

- 10B






And, 

 F

Fclock -minute 

sampling cycles in clock - minute

nsampling cycles in clock -minute

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

BAL‐001‐2 
January 1, 2013 

Page 9 of 13 

Standard BAL‐001‐2 – Real Power Balancing Control Performance 

 RACE

* Fclock-minute 
CFclock- minute  

  10 B  clock-minute

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 clock‐
hour). 

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) and the data samples for each 24‐
hour 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

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

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

CF12-month 

 (CF

month -i

i 1

)(none-minute samples in month i )]

12

 [n
i 1

( one - minute samples in month)-i

]

To ensure that the average Reporting ACE and Frequency Error calculated for any one‐
minute 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 one‐
minute 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 
BAL‐001‐2 
January 1, 2013 

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Standard BAL‐001‐2 – Real Power Balancing Control Performance 
Settings with the Reporting ACE and Frequency Bias Settings of the Balancing Authority 
receiving the Regulation Service.   

BAL‐001‐2 
January 1, 2013 

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Standard BAL‐001‐2 – Real Power Balancing Control Performance 
Attachment 2 

Equations Supporting Requirement R2 and Measure M2 

When actual frequency is equal to Scheduled Frequency, BAALHigh and BAALLow do not apply. 
When actual frequency is less than Scheduled Frequency, BAALHigh does not apply, and 
BAALLow is calculated as: 
BAAL Low   10 Bi  FTL Low  FS 

FTL Low  FS 
FA  FS 

When actual frequency is greater than Scheduled Frequency, BAALLow does not apply and 
the BAALHigh is calculated as:  

BAALHigh   10 Bi  FTLHigh  FS 

FTL

High

 FS 

FA  FS 

Where: 
BAALLow 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 
Bi is the Frequency Bias Setting for a Balancing Authority (expressed as MW/0.1 Hz) 
FA is the measured frequency in Hz. 
FS is the scheduled frequency in Hz. 
FTLLow is the Low Frequency Trigger Limit (calculated as FS ‐ 3ε1I Hz) 
FTLHigh is the High Frequency Trigger Limit (calculated as FS + 3ε1I  Hz)  
Where ε1I is the constant derived from a targeted frequency bound for each 
Interconnection as follows:  



Eastern Interconnection ε1I = 0.018 Hz  



Western Interconnection ε1I = 0.0228 Hz  



ERCOT Interconnection ε1I = 0.030 Hz 



Quebec Interconnection ε1I = 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 
BAL‐001‐2 
January 1, 2013 

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Standard BAL‐001‐2 – Real Power Balancing Control Performance 
data is available or valid, then that one‐minute interval is excluded from the BAAL 
calculation.  

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.   

BAL‐001‐2 
January 1, 2013 

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Standard BAL‐001‐1BAL‐001‐2 – 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 2010‐
14.1, Balancing Authority Reliability‐based Controls – Reserves) into formal standards 
development on July 13, 2011.  
8. The draft standard was posted for 30‐day formal industry comment period from June 4, 
2012 through July 3, 2012. 
Proposed Action Plan and Description of Current Draft: 
This is the second posting of the proposed new standard.  This proposed draft standard will be 
posted for a 45‐day formal comment period beginning on March 12, 2013 through April 25, 
2013.  

Future Development Plan: 
Anticipated Actions 
1. Second posting 

Anticipated Date 
March/April 2013 

2. Initial Ballot 

April 2013 

3. Recirculation Ballot 

October 2013 

4. NERC BOT adoption. 

November 2013 

BAL‐001‐1BAL‐001‐2 
January 1, 2013 

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Standard BAL‐001‐1BAL‐001‐2 – 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. 
Regulation Reserve Sharing Group:  A group whose members consist of two or more Balancing 
Authorities that collectively maintain, allocate, and supply operatingthe regulating  reserve 
required for eachall member  Balancingmember Balancing Authorityies to  use in meeting 
theapplicable regulating standards requirements associated with Control Performance Standard 
1. 
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 all the Balancing Authorities participating inthat 
make up the Regulation Reserve Sharing Group at the time of measurement.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 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). 
Reporting ACE is calculated as follows: 

Reporting ACE = (NIA − NIS) − 10B (FA − FS) − IME + IATEC 

Where: 
NIA (Actual Net Interchange) 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 (Scheduled Net Interchange) is the algebraic sum of all scheduled megawatt 
transfers, including Dynamic Schedules, with adjacent Balancing Authorities, and taking 
into account the effects of schedule ramps.  Balancing Authorities directly connected via 
BAL‐001‐1BAL‐001‐2 
January 1, 2013 

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Standard BAL‐001‐1BAL‐001‐2 – Real Power Balancing Control Performance 
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.  
FS (Scheduled Frequency) is 60.0 Hz, except during a time correction. 
IME (Interchange Meter Error) is the meter error correction factor and represents the 
difference between the integrated hourly average of the net interchange actual (NIA) 
and the cumulative hourly net Interchange energy measurement (in megawatt‐hours). 
IATEC (Automatic Time Error Correction) is the addition of a component to the ACE 
equation that modifies the control point for the purpose of continuously paying back 
Primary Inadvertent Interchange to correct accumulated time error.  Automatic Time 
Error Correction is only applicable in the Western interconnection. 
on/off peak

IATEC

 PII

accum

1  Y * H

 when operating in Automatic Time Error Correction control mode.  

 IATEC shall be zero when operating in any other AGC mode. 


Y = B / BS. 



H = Number of Hours used to payback Primary Inadvertent Interchange energy. The 
value of H is set to 3. 



BS = Frequency Bias for the Interconnection (MW / 0.1 Hz). 



Primary Inadvertent Interchange (PIIhourly) is (1‐Y) * (IIactual ‐ B * ΔTE/6) 



IIactual is the hourly Inadvertent Interchange for the last hour. 



ΔTE is the hourly change in system Time Error as distributed by the Interconnection 
Time Monitor. Where: 

ΔTE = TEend hour – TEbegin hour – TDadj – (t)*(TEoffset) 



TDadj is the Reliability Coordinator adjustment for differences with Interconnection 
Time Monitor control center clocks. 



t is the number of minutes of Manual Time Error Correction that occurred during the 
hour. 



TEoffset is 0.000 or +0.020 or ‐0.020.   



PIIaccum is the Balancing Authority’s accumulated PIIhourly in MWh. An On‐Peak and 
Off‐Peak accumulation accounting is required. 

BAL‐001‐1BAL‐001‐2 
January 1, 2013 

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Standard BAL‐001‐1BAL‐001‐2 – Real Power Balancing Control Performance 
Where: 

PII

on/off peak
accum

 = last period’s 

on/off peak

PII

accum

 + PIIhourly 

All NERC Interconnections with multiple Balancing Authorities operate using the principles 
of Tie‐line Bias (TLB) Control and require the use of an ACE equation similar to the 
Reporting ACE defined above.  Any modification(s) to this specified Reporting ACE 
equation that is(are) implemented for all BAs on an interconnection and is(are) consistent 
with the following four principles will provide a valid alternative Reporting ACE equation 
consistent with the measures included in this standard. 
1. All portions of the interconnection are included in one area or another so that 
the sum of all area generation, loads and losses is the same as total system 
generation, load and losses. 
2. The algebraic sum of all area net interchange schedules and all net interchange 
actual values is equal to zero at all times. 
3. The use of a common scheduled frequency FS for all areas at all times. 
4. The absence of metering or computational errors.  (The inclusion and use of the 
IME term to account for known metering or computational errors.) 

Interconnection: When capitalized, any one of the four major electric system networks in North 
America: Eastern, Western, ERCOTTexas and Quebec.

BAL‐001‐1BAL‐001‐2 
January 1, 2013 

Page 4 of 15 

Standard BAL‐001‐1BAL‐001‐2 – Real Power Balancing Control Performance 
A. Introduction
1.

Title: 

Real Power Balancing Control Performance  

2.

Number: 

BAL‐001‐1BAL‐001‐2 

3.

Purpose: 

To control Interconnection frequency within defined limits. 

4.

Applicability: 
4.1. Balancing Authority 
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. 
4.1.2 A Balancing Authority that is a member of a 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 
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.   

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.   
4.1.2  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.

The Responsible EntityEach Balancing Authority shall operate such that the Balancing 
Authority’s Control Performance Standard 1 (CPS1), as applicable and as calculated in 
accordance with 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] 

BAL‐001‐1BAL‐001‐2 
January 1, 2013 

Page 5 of 15 

Standard BAL‐001‐1BAL‐001‐2 – Real Power Balancing Control Performance 
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 its clock‐minute Balancing Authority ACE Limit 
(BAAL), as calculated in Attachment 2, for the applicable Interconnection in which the 
Balancing Authorityit or Regulation Reserve Sharing Group operates to support 
Interconnection frequency.[Violation Risk Factor: Medium] [Time Horizon: Real‐time 
Operations] 

C. Measures 
M1. The Responsible EntityEach 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 
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.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 Responsible Entity 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 Regulation Reserve Sharing Group Reporting Ace, or Reporting 
ACE, CPS1, and BAAL shall be retained in digital format at the same scan rate at 

BAL‐001‐1BAL‐001‐2 
January 1, 2013 

Page 6 of 15 

Standard BAL‐001‐1BAL‐001‐2 – Real Power Balancing Control Performance 
which the Reporting ACEce is calculated for the current year, plus three previous 
calendar years.     
If a Responsible Entity 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 
Spot Checking 
Compliance Investigation 
Self‐Reporting 
Complaints 
1.4. Additional Compliance Information 
None. 
2.

Violation Severity Levels 
R
#

Lower VSL

R1  The CPS 1 value 
of the 
RResponsible 
Entity,’s or thea 
Balancing 
Authority’s,  
area value of 
CPS1, on a 
rolling 12‐
month basis, is 
less than 100 
percent but 
greater than or 
equal to 95 
percent for the 
applicable 
Interconnection. 
R2  The Balancing 
Authority 
BAL‐001‐1BAL‐001‐2 
January 1, 2013 

Moderate VSL

High VSL

Severe VSL

The CPS 1 value 
of the 
Responsible 
Entity, on a 
rolling 12‐
month basis, is 
less than 95 
percent, but 
greater than or 
equal to 90 
percent for the 
applicable 
Interconnection.

The CPS 1 value 
of the 
Responsible 
Entity, on a 
rolling 12‐
month basis, is 
less than 90 
percent, but 
greater than or 
equal to 85 
percent for the 
applicable 
Interconnection.

The CPS 1 value of the 
Responsible Entity, on a 
rolling 12‐month basis, 
is less than 85 percent 
for the applicable 
Interconnection. 

The Balancing 
Authority 

The Balancing 
Authority 

The Balancing Authority 
exceeded its clock‐

Page 7 of 15 

Standard BAL‐001‐1BAL‐001‐2 – Real Power Balancing Control Performance 
exceeded its 
clock‐minute 
BAAL for more 
than 30 
consecutive 
clock minutes 
but forless than 
or equal to 45 
consecutive 
clock minutes or 
less. 

exceeded its 
clock‐minute 
BAAL for greater 
than 45 
consecutive 
clock minutes 
but forless than 
or equal to 60 
consecutive 
clock minutes or 
less. 

exceeded its 
minute BAAL for greater 
clock‐minute 
than 75 consecutive 
BAAL for greater  clock‐minutes. 
than 60 
consecutive 
clock minutes 
but for less than 
or equal to 75 
consecutive 
clock minutes or 
less. 

E. Regional Variances 
None. 
F. Associated Documents 
BAL‐001‐1BAL‐001‐2, Real Power Balancing Control Performance Standard Background 
Document 
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 

BAL‐001‐1BAL‐001‐2 
January 1, 2013 

Page 8 of 15 

Standard BAL‐001‐1BAL‐001‐2 – Real Power Balancing Control Performance 
0.1a 

1 

BAL‐001‐1BAL‐001‐2 
January 1, 2013 

May 13, 2009 

Approved by FERC 

Inclusion of BAAL and WECC Variance and 
exclusion of CPS2 

Revision 

Page 9 of 15 

Standard BAL‐001‐1BAL‐001‐2 – 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 for the most recent consecutive over a 12‐calendar months period, 
divided by the square of the target frequency bound: 
CF =

CF

12 ‐ month

(ε1I ) 2

whereWhere ε1I is the constant derived from a targeted frequency bound for each 
Interconnection as follows:  


Eastern Interconnection ε1I = 0.018 Hz  



Western Interconnection ε1I = 0.0228 Hz  



ERCOT Interconnection ε1I = 0.030 Hz 



Quebec Interconnection ε1I = 0.021 Hz  

The rating index CF12‐month is derived from the most recent consecutive 12‐calendar 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 − NIS) − 10B (FA − FS) − NME 
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‐001‐1BAL‐001‐2 
January 1, 2013 

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Standard BAL‐001‐1BAL‐001‐2 – 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 (RACE) and for Frequency Error) for each 
sampling cycle during a given clock minute. 

 RACE


  10 B  clock-minute

  RACE
sampling cycles in clock - minute


nsampling cycles in clock-minute

- 10B






 ACE 


  10 B  clock -minute

  ACEsampling cycles in clock -minute


nsampling cycles in clock -minute

- 10B






andAnd, 

 F

Fclock -minute 

sampling cycles in clock - minute

nsampling cycles in clock -minute

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

 RACE

* Fclock-minute 
CFclock- minute  

  10 B  clock-minute

 ACE 

CFclock -minute  
* Fclock -minute 

  10 B  clock -minute

BAL‐001‐1BAL‐001‐2 
January 1, 2013 

Page 11 of 15 

Standard BAL‐001‐1BAL‐001‐2 – Real Power Balancing Control Performance 

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 clock‐
hour). 

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) and the data samples for each 24‐
hour 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

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

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

CF12-month 

 (CF

month -i

i 1

)(none-minute samples in month i )]

12

 [n
i 1

( one - minute samples in month)-i

]

To ensure that the average Reporting ACE and Frequency Error calculated for any one‐
minute 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 one‐
minute 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.   

BAL‐001‐1BAL‐001‐2 
January 1, 2013 

Page 12 of 15 

Standard BAL‐001‐1BAL‐001‐2 – Real Power Balancing Control Performance 
A Balancing Authority receiving Overlap Regulation Service is not subject to 
CPS1compliance evaluation.  

BAL‐001‐1BAL‐001‐2 
January 1, 2013 

Page 13 of 15 

Standard BAL‐001‐1BAL‐001‐2 – Real Power Balancing Control Performance 
Attachment 2 

Equations Supporting Requirement R2 and Measure M2 

When actual frequency is equal to Scheduled Frequency60 Hz, BAALHigh and BAALLow do not 
apply. 
When actual frequency is less than Scheduled Frequency60 Hz, BAALHigh does not apply, and 
BAALLow is calculated as: 

FTL Low  FS 
FA  FS 
FTL Low  60 
BAAL Low   10 Bi  FTL Low  60  
FA  60 

BAAL Low   10 Bi  FTL Low  FS 

When actual frequency is greater than Scheduled Frequency60 Hz, BAALLow does not apply 
and the BAALHigh is calculated as:  

BAALHigh   10 Bi  FTLHigh  FS 

BAALHigh   10 Bi  FTLHigh  60

FTL

 FS 

FTL

 60

High

FA  FS 
High

FA  60

Where: 
BAALLow 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 
Bi 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. 
FS is the scheduled frequency in Hz. 
FTLLow is the Low Frequency Trigger Limit (calculated as FS 60‐ 3ε1I Hz) 
FTLHigh is the High Frequency Trigger Limit (calculated as FS60 + 3ε1I  Hz)  
Where ε1I is the constant derived from a targeted frequency bound for each 
Interconnection as follows:  

BAL‐001‐1BAL‐001‐2 
January 1, 2013 



Eastern Interconnection ε1I = 0.018 Hz  



Western Interconnection ε1I = 0.0228 Hz  



ERCOT Interconnection ε1I = 0.030 Hz 

Page 14 of 15 

Standard BAL‐001‐1BAL‐001‐2 – Real Power Balancing Control Performance 

 Quebec Interconnection ε1I = 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.  

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‐001‐1BAL‐001‐2 
January 1, 2013 

Page 15 of 15 

Implementation Plan

Project 2010-14.1 Balancing Authority Reliability-based Controls
- Reserves
Implementation Plan for BAL‐001‐2 – Real Power Balancing Control Performance 

Approvals Required 
BAL‐001‐2 – Real Power Balancing Control Performance 

Prerequisite Approvals 
None 

Revisions to Glossary Terms 
The following definitions shall become effective when BAL‐001‐2 becomes effective:  

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. 

Reporting ACE:  The scan rate values of a Balancing Authority’s Area Control Error (ACE) 
measured in MW, which includes the difference between the Balancing Authority’s net actual 
Interchange and its scheduled Interchange, plus its Frequency Bias obligation, plus any known 
meter error. 

Reporting ACE is calculated as follows: 

Reporting ACE = (NIA − NIS) − 10B (FA − FS) − IME 

Where: 

NIA (Actual Net Interchange) 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 (Scheduled Net Interchange) is the algebraic sum of all scheduled megawatt 
transfers, including Dynamic Schedules, with adjacent Balancing Authorities, and taking 
into account the effects of schedule ramps.  Balancing Authorities directly connected via 
asynchronous ties to another Interconnection may include or exclude 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.  
FS (Scheduled Frequency) is 60.0 Hz, except during a time correction. 
IME (Interchange Meter Error) is the meter error correction factor and represents the 
difference between the integrated hourly average of the net interchange actual (NIA) 
and the cumulative hourly net Interchange energy measurement (in megawatt‐hours). 

All NERC Interconnections with multiple Balancing Authorities operate using the principles 
of Tie‐line Bias (TLB) Control and require the use of an ACE equation similar to the Reporting 
ACE defined above.  Any modification(s) to this specified Reporting ACE equation that 
is(are) implemented for all BAs on an interconnection and is(are) consistent with the 
following four principles will provide a valid alternative Reporting ACE equation consistent 
with the measures included in this standard. 
1. All portions of the interconnection are included in one area or another so that the 
sum of all area generation, loads and losses is the same as total system generation, 
load and losses. 
2. The algebraic sum of all area net interchange schedules and all net interchange 
actual values is equal to zero at all times. 
3. The use of a common scheduled frequency FS for all areas at all times. 
4. The absence of metering or computational errors.  (The inclusion and use of the IME 
term to account for known metering or computational errors.) 
Interconnection:  When capitalized, any one of the four major electric system networks in North 
America: Eastern, Western, ERCOT and Quebec. 

BAL‐001‐2 – Real Power Balancing Control Performance 
February, 2013 

2 

The existing definition of Interconnection should be retired at midnight of the day immediately prior to 
the effective date of BAL‐001‐2, 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 
Regulation Reserve Sharing Group 

Applicable Facilities 
N/A 

Conforming Changes to Other Standards 
None 

Effective Dates 
BAL‐001‐2 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  effective  pursuant  to  the  laws  applicable  to  such  ERO 
governmental authorities.   

Justification 
The six‐month period for implementation of BAL‐001‐2 will provide ample time for Balancing 
Authorities to make necessary modifications to existing software programs to perform the BAAL 
calculations for compliance. 

Retirements 

BAL‐001‐2 – Real Power Balancing Control Performance 
February, 2013 

3 

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‐001‐2 in the particular jurisdiction in which the new 
standard is becoming effective. 

BAL‐001‐2 – Real Power Balancing Control Performance 
February, 2013 

4 

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 
IRO‐005‐2a — Reliability Coordination — Current Day Operations 

BAL‐001‐2 – Real Power Balancing Control Performance 
February, 2013 

5 

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‐001‐2 – Real Power Balancing Control Performance 
February, 2013 

6 

Implementation Plan

Project 2010-14.1 Balancing Authority Reliability-based Controls
- Reserves
Implementation Plan for BAL‐001‐1 2 – Real Power Balancing Control Performance 

Approvals Required 
BAL‐001‐21 – Real Power Balancing Control Performance 

Prerequisite Approvals 
None 

Revisions to Glossary Terms 
The following definitions shall become effective when BAL‐001‐21 becomes effective:  

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. 
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 net actual Interchange and its scheduled Interchange, plus its Frequency Bias 
obligation, plus any known meter error. 

Reporting ACE is calculated as follows: 

Reporting ACE = (NIA − NIS) − 10B (FA − FS) − IME 

Where: 
NIA (Actual Net Interchange) 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 (Scheduled Net Interchange) is the algebraic sum of all scheduled megawatt 
transfers, including Dynamic Schedules, with adjacent Balancing Authorities, and taking 
into account the effects of schedule ramps.  Balancing Authorities directly connected via 
asynchronous ties to another Interconnection may include or exclude 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.  
FS (Scheduled Frequency) is 60.0 Hz, except during a time correction. 
IME (Interchange Meter Error) is the meter error correction factor and represents the 
difference between the integrated hourly average of the net interchange actual (NIA) 
and the cumulative hourly net Interchange energy measurement (in megawatt‐hours). 

All NERC Interconnections with multiple Balancing Authorities operate using the principles 
of Tie‐line Bias (TLB) Control and require the use of an ACE equation similar to the Reporting 
ACE defined above.  Any modification(s) to this specified Reporting ACE equation that 
is(are) implemented for all BAs on an interconnection and is(are) consistent with the 
following four principles will provide a valid alternative Reporting ACE equation consistent 
with the measures included in this standard. 
1. All portions of the interconnection are included in one area or another so that the 
sum of all area generation, loads and losses is the same as total system generation, 
load and losses. 
2. The algebraic sum of all area net interchange schedules and all net interchange 
actual values is equal to zero at all times. 
3. The use of a common scheduled frequency FS for all areas at all times. 
1.4. The absence of metering or computational errors.  (The inclusion and use of the 
IME term to account for known metering or computational errors.) 

BAL‐001‐2 – Real Power Balancing Control Performance 
February, 2013 

2 

Interconnection:  When capitalized, any one of the four major electric system networks in North 
America: Eastern, Western, ERCOTTexas and Quebec. 

The existing definition of Interconnection should be retired at midnight of the day immediately prior to 
the effective date of BAL‐001‐12, 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 
Regulation Reserve Sharing Group 

Applicable Facilities 
N/A 

Conforming Changes to Other Standards 
None 

Effective Dates 
BAL‐001‐1 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  effective  pursuant  to  the  laws  applicable  to  such  ERO 
governmental authorities.   

Justification 
The six‐month period for implementation of BAL‐001‐1 2 will provide ample time for Balancing 
Authorities to make necessary modifications to existing software programs to perform the BAAL 
calculations for compliance. 

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February, 2013 

3 

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 2 in the particular jurisdiction in which the new 
standard is becoming effective. 

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February, 2013 

4 

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 
IRO‐005‐2a — Reliability Coordination — Current Day Operations 

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5 

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 

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February, 2013 

6 

Unofficial Comment Form
Project 2010-14.1 Balancing Authority Reliability-based Control
BAL-001-2 − 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 double‐
clicking 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 

BAL-001-2 – Real Power
Balancing Control
Performance 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

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

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Introduction
This document provides background on the development, testing, and implementation of BAL‐
001‐2 ‐ 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: 
 Lack of theoretical justification 
 Large ACE treated the same as a small ACE, regardless of direction 
 Independent of Interconnection frequency 

In 1996, a new NERC policy was approved which used CPS1, CPS2, and DCS.   
CPS1is a: 
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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 12‐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.   
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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. 
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 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 
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 
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Real Power Balancing Control Performance Standard Background Document 
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 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.  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 
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 
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Real Power Balancing Control Performance Standard Background Document 
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 that 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. 

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. 

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 
February, 2013

7

59.700
59.710
59.720
59.730
59.740
59.750
59.760
59.770
59.780
59.790
59.800
59.810
59.820
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59.900
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60.000
60.010
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60.030
60.040
60.050
60.060
60.070
60.080
60.090
60.100
60.110
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60.180
60.190
60.200
60.210
60.220
60.230
60.240
60.250
60.260
60.270
60.280
60.290
60.300

pu ACE / Bias
59.700
59.710
59.720
59.730
59.740
59.750
59.760
59.770
59.780
59.790
59.800
59.810
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59.830
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59.850
59.860
59.870
59.880
59.890
59.900
59.910
59.920
59.930
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59.950
59.960
59.970
59.980
59.990
60.000
60.010
60.020
60.030
60.040
60.050
60.060
60.070
60.080
60.090
60.100
60.110
60.120
60.130
60.140
60.150
60.160
60.170
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60.190
60.200
60.210
60.220
60.230
60.240
60.250
60.260
60.270
60.280
60.290
60.300

pu ACE / Bias

Real Power Balancing Control Performance Standard Background Document 

2.5
pu ACE/Bias=BAAL@60 Hz & pu ACE/Bias=CPS1@100%

BAAL Based on 60 Hz w/o TEC

2.0

1.5

1.0

0.5

0.0

‐0.5

‐1.0
BAAL @ 60.00

CPS1=100 @ 60.00

‐1.5

‐2.0

‐2.5

Frequency (Hz)

Figure 2. BAAL Based on 60 Hz w/o TEC

2.5
pu ACE/Bias=BAAL@60 Hz & pu ACE/Bias=CPS1@100%

BAAL Based on 60 Hz w/ Fast TEC

2.0

1.5

1.0

0.5

0.0

‐0.5

‐1.0

‐1.5

BAAL less than 
ACE when 
CPS1 = 100%
BAAL @ 60.00

BAL‐001‐2 ‐ Background Document 
February, 2013
CPS1=100 @ 59.98

Fast TEC

‐2.0

‐2.5

Frequency (Hz)

Figure 1. BAAL Based on 60 Hz w/ Fast TEC

8

59.700
59.710
59.720
59.730
59.740
59.750
59.760
59.770
59.780
59.790
59.800
59.810
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59.830
59.840
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59.880
59.890
59.900
59.910
59.920
59.930
59.940
59.950
59.960
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59.980
59.990
60.000
60.010
60.020
60.030
60.040
60.050
60.060
60.070
60.080
60.090
60.100
60.110
60.120
60.130
60.140
60.150
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60.170
60.180
60.190
60.200
60.210
60.220
60.230
60.240
60.250
60.260
60.270
60.280
60.290
60.300

pu ACE / Bias
59.700
59.710
59.720
59.730
59.740
59.750
59.760
59.770
59.780
59.790
59.800
59.810
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59.830
59.840
59.850
59.860
59.870
59.880
59.890
59.900
59.910
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59.970
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59.990
60.000
60.010
60.020
60.030
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60.050
60.060
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60.090
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60.190
60.200
60.210
60.220
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60.240
60.250
60.260
60.270
60.280
60.290
60.300

pu ACE / Bias

Real Power Balancing Control Performance Standard Background Document 

2.5
pu ACE/Bias=BAAL@60 Hz & pu ACE/Bias=CPS1@100%

BAAL Based on 60 Hz w/ Slow TEC

2.0

1.5

1.0

BAAL less than 
ACE when 
CPS1 = 100%

0.5

0.0

‐0.5

‐1.0
BAAL @ 60.00

CPS1=100 @ 60.02

‐1.5
Slow TEC

‐2.0

‐2.5

Frequency (Hz)

Figure 4. BAAL Based on 60 Hz w/ Slow TEC

2.5
pu ACE/Bias=BAAL@60 Hz & pu ACE/Bias=CPS1@100%

BAAL Based on 60 Hz Summary

2.0

1.5

1.0

BAAL less than 
ACE when 
CPS1 = 100%

0.5

0.0

‐0.5

‐1.0

‐1.5

BAAL less than 
ACE when 
CPS1 = 100%
BAAL @ 60.00

BAL‐001‐2 ‐ Background Document 
February, 2013
CPS1=100 @ 60.02

CPS1=100 @ 60.00

CPS1=100 @ 59.98

‐2.0

Slow TEC

Fast TEC

‐2.5

Frequency (Hz)

Figure 3. BAAL Based on 60 Hz Summary

9

59.700
59.710
59.720
59.730
59.740
59.750
59.760
59.770
59.780
59.790
59.800
59.810
59.820
59.830
59.840
59.850
59.860
59.870
59.880
59.890
59.900
59.910
59.920
59.930
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59.950
59.960
59.970
59.980
59.990
60.000
60.010
60.020
60.030
60.040
60.050
60.060
60.070
60.080
60.090
60.100
60.110
60.120
60.130
60.140
60.150
60.160
60.170
60.180
60.190
60.200
60.210
60.220
60.230
60.240
60.250
60.260
60.270
60.280
60.290
60.300

pu ACE / Bias
59.700
59.710
59.720
59.730
59.740
59.750
59.760
59.770
59.780
59.790
59.800
59.810
59.820
59.830
59.840
59.850
59.860
59.870
59.880
59.890
59.900
59.910
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59.990
60.000
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60.210
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60.260
60.270
60.280
60.290
60.300

pu ACE / Bias

Real Power Balancing Control Performance Standard Background Document 

2.5

BAAL Based on Scheduled Frequency w/o TEC
pu ACE/Bias=BAAL@Scheduled Frequency & pu ACE/Bias=CPS1@100%

2.0

1.5

1.0

0.5

0.0

‐0.5

‐1.0
BAAL @ 60.00

CPS1=100 @ 60.00

‐1.5

‐2.0

‐2.5

Frequency (Hz)

Figure 6. BAAL Based on Scheduled Frequency w/o TEC

2.5

BAAL Based on Scheduled Frequency w/ Fast TEC

pu ACE/Bias=BAAL@Scheduled Frequency & pu ACE/Bias=CPS1@100%

2.0

1.5

1.0

0.5

0.0

‐0.5

‐1.0
BAAL @ 59.98

CPS1=100 @ 59.98

‐1.5
Fast TEC

‐2.0

‐2.5

Frequency (Hz)

Figure 5. BAAL Based o Scheduled Frequency w/ Fast TEC

BAL‐001‐2 ‐ Background Document 
February, 2013

1
0

59.700
59.710
59.720
59.730
59.740
59.750
59.760
59.770
59.780
59.790
59.800
59.810
59.820
59.830
59.840
59.850
59.860
59.870
59.880
59.890
59.900
59.910
59.920
59.930
59.940
59.950
59.960
59.970
59.980
59.990
60.000
60.010
60.020
60.030
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60.050
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60.080
60.090
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60.110
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60.180
60.190
60.200
60.210
60.220
60.230
60.240
60.250
60.260
60.270
60.280
60.290
60.300

pu ACE / Bias
59.700
59.710
59.720
59.730
59.740
59.750
59.760
59.770
59.780
59.790
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59.870
59.880
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59.900
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59.980
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60.000
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60.060
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60.210
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60.280
60.290
60.300

pu ACE / Bias

Real Power Balancing Control Performance Standard Background Document 

2.5

BAAL Based on Scheduled Frequency w/ Slow TEC
pu ACE/Bias=BAAL@Scheduled Frequency & pu ACE/Bias=CPS1@100%

2.0

1.5

1.0

0.5

0.0

‐0.5

‐1.0
BAAL @ 60.02

CPS1=100 @ 60.02

‐1.5
Slow TEC

‐2.0

‐2.5

Frequency (Hz)

Figure 7. BAAL Based on Scheduled Frequency w/ Slow TEC

2.5

BAAL Based on Scheduled Frequency Summary

pu ACE/Bias=BAAL@Scheduled Frequency & pu ACE/Bias=CPS1@100%

2.0

1.5

1.0

0.5

0.0

‐0.5

‐1.0
BAAL @ 60.02

BAAL @ 60.00

‐1.5
BAAL @ 59.98

CPS1=100 @ 60.02

CPS1=100 @ 60.00

‐2.0

CPS1=100 @ 59.98

Slow TEC

‐2.5

Fast TEC

Frequency (Hz)

Figure 8. BAAL Based on Scheduled Frequency Summary

BAL‐001‐2 ‐ Background Document 
February, 2013

1
1

BAL-001-1 2 – Real
Power Balancing Control
Performance 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

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

BAL‐001‐1 2 ‐ Background Document 
February, 2013

2

Real Power Balancing Control Performance Standard Background Document 

Introduction
This document provides background on the development, testing, and implementation of BAL‐
001‐1 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‐001‐1 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: 
 Lack of theoretical justification 
 Large ACE treated the same as a small ACE, regardless of direction 
 Independent of Interconnection frequency 

In 1996, a new NERC policy was approved which used CPS1, CPS2, and DCS.   
CPS1is a: 
BAL‐001‐1 2 ‐ Background Document 
February, 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‐001‐1 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 rRequires Balancing Authorities to comply 90 percent of the time as a minimum.  

Background and Rationale by Requirement
Requirement 1 
R1. The Responsible EntityEach Balancing Authority shall operate such that the Balancing 
Authority’s Control Performance Standard 1 (CPS1), (as calculated in accordance with 
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.  
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‐001‐1 2 ‐ Background Document 
February, 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. 
Requirement 2 
R2. Each Balancing Authority shall operate such that its clock‐minute average of Rreporting 
ACE does not exceed its clock‐minute Balancing Authority ACE Limit (BAAL) 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 the 
Balancing Authorityit 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 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 
Frequency60 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 Scheduled Frequency60 Hz, and BAAL high is for Interconnection 
frequency values greater than Scheduled Frequency60 Hz.  BAAL values for each Balancing 
Authority are dynamic and change as Interconnection frequency changes.  For example, as 
Interconnection frequency moves from Scheduled Frequency60 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.  

BAL‐001‐1 2 ‐ Background Document 
February, 2013

5

Real Power Balancing Control Performance Standard Background Document 
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 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.  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 
forsignificant hours when a Balancing Authority’s ACE value to be unbounded for a specific 
amount of time during a calendar months are unbounded. 

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 
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 
BAL‐001‐1 2 ‐ Background Document 
February, 2013

6

Real Power Balancing Control Performance Standard Background Document 
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 that 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. 

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. 

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‐001‐1 2 ‐ Background Document 
February, 2013

7

Real Power Balancing Control Performance Standard Background Document 
Finally, resolving this conflict reduces the detrimental impact that BAAL has on some smaller 
BAs on the Western Interconnection during TEC. 

BAL‐001‐1 2 ‐ Background Document 
February, 2013

8

59.700
59.710
59.720
59.730
59.740
59.750
59.760
59.770
59.780
59.790
59.800
59.810
59.820
59.830
59.840
59.850
59.860
59.870
59.880
59.890
59.900
59.910
59.920
59.930
59.940
59.950
59.960
59.970
59.980
59.990
60.000
60.010
60.020
60.030
60.040
60.050
60.060
60.070
60.080
60.090
60.100
60.110
60.120
60.130
60.140
60.150
60.160
60.170
60.180
60.190
60.200
60.210
60.220
60.230
60.240
60.250
60.260
60.270
60.280
60.290
60.300

pu ACE / Bias
59.700
59.710
59.720
59.730
59.740
59.750
59.760
59.770
59.780
59.790
59.800
59.810
59.820
59.830
59.840
59.850
59.860
59.870
59.880
59.890
59.900
59.910
59.920
59.930
59.940
59.950
59.960
59.970
59.980
59.990
60.000
60.010
60.020
60.030
60.040
60.050
60.060
60.070
60.080
60.090
60.100
60.110
60.120
60.130
60.140
60.150
60.160
60.170
60.180
60.190
60.200
60.210
60.220
60.230
60.240
60.250
60.260
60.270
60.280
60.290
60.300

pu ACE / Bias

Real Power Balancing Control Performance Standard Background Document 

2.5

‐1.5

pu ACE/Bias=BAAL@60 Hz & pu ACE/Bias=CPS1@100%

BAAL Based on 60 Hz w/o TEC

2.0

1.5

1.0

0.5

0.0

‐0.5

‐1.0
BAAL @ 60.00

CPS1=100 @ 60.00

‐1.5

‐2.0

‐2.5

Frequency (Hz)

Figure 2. BAAL Based on 60 Hz w/o TEC

2.5
pu ACE/Bias=BAAL@60 Hz & pu ACE/Bias=CPS1@100%

BAAL Based on 60 Hz w/ Fast TEC

2.0

1.5

1.0

0.5

0.0

‐0.5

‐1.0

BAAL less than 
ACE when 
CPS1 = 100%
BAAL @ 60.00

BAL‐001‐1 2 ‐ Background Document 
February, 2013
CPS1=100 @ 59.98

Fast TEC

‐2.0

‐2.5

Frequency (Hz)

Figure 1. BAAL Based on 60 Hz w/ Fast TEC

9

59.700
59.710
59.720
59.730
59.740
59.750
59.760
59.770
59.780
59.790
59.800
59.810
59.820
59.830
59.840
59.850
59.860
59.870
59.880
59.890
59.900
59.910
59.920
59.930
59.940
59.950
59.960
59.970
59.980
59.990
60.000
60.010
60.020
60.030
60.040
60.050
60.060
60.070
60.080
60.090
60.100
60.110
60.120
60.130
60.140
60.150
60.160
60.170
60.180
60.190
60.200
60.210
60.220
60.230
60.240
60.250
60.260
60.270
60.280
60.290
60.300

pu ACE / Bias
59.700
59.710
59.720
59.730
59.740
59.750
59.760
59.770
59.780
59.790
59.800
59.810
59.820
59.830
59.840
59.850
59.860
59.870
59.880
59.890
59.900
59.910
59.920
59.930
59.940
59.950
59.960
59.970
59.980
59.990
60.000
60.010
60.020
60.030
60.040
60.050
60.060
60.070
60.080
60.090
60.100
60.110
60.120
60.130
60.140
60.150
60.160
60.170
60.180
60.190
60.200
60.210
60.220
60.230
60.240
60.250
60.260
60.270
60.280
60.290
60.300

pu ACE / Bias

Real Power Balancing Control Performance Standard Background Document 

2.5

‐1.5

pu ACE/Bias=BAAL@60 Hz & pu ACE/Bias=CPS1@100%

BAAL Based on 60 Hz w/ Slow TEC

2.0

1.5

1.0

BAAL less than 
ACE when 
CPS1 = 100%

0.5

0.0

‐0.5

‐1.0
BAAL @ 60.00

CPS1=100 @ 60.02

‐1.5
Slow TEC

‐2.0

‐2.5

Frequency (Hz)

Figure 4. BAAL Based on 60 Hz w/ Slow TEC

2.5
pu ACE/Bias=BAAL@60 Hz & pu ACE/Bias=CPS1@100%

BAAL Based on 60 Hz Summary

2.0

1.5

1.0

BAAL less than 
ACE when 
CPS1 = 100%

0.5

0.0

‐0.5

‐1.0

BAAL less than 
ACE when 
CPS1 = 100%
BAAL @ 60.00

BAL‐001‐1 2 ‐ Background Document 
February, 2013
CPS1=100 @ 60.02

CPS1=100 @ 60.00

CPS1=100 @ 59.98

‐2.0

Slow TEC

Fast TEC

‐2.5

Frequency (Hz)

Figure 3. BAAL Based on 60 Hz Summary

1
0

59.700
59.710
59.720
59.730
59.740
59.750
59.760
59.770
59.780
59.790
59.800
59.810
59.820
59.830
59.840
59.850
59.860
59.870
59.880
59.890
59.900
59.910
59.920
59.930
59.940
59.950
59.960
59.970
59.980
59.990
60.000
60.010
60.020
60.030
60.040
60.050
60.060
60.070
60.080
60.090
60.100
60.110
60.120
60.130
60.140
60.150
60.160
60.170
60.180
60.190
60.200
60.210
60.220
60.230
60.240
60.250
60.260
60.270
60.280
60.290
60.300

pu ACE / Bias
59.700
59.710
59.720
59.730
59.740
59.750
59.760
59.770
59.780
59.790
59.800
59.810
59.820
59.830
59.840
59.850
59.860
59.870
59.880
59.890
59.900
59.910
59.920
59.930
59.940
59.950
59.960
59.970
59.980
59.990
60.000
60.010
60.020
60.030
60.040
60.050
60.060
60.070
60.080
60.090
60.100
60.110
60.120
60.130
60.140
60.150
60.160
60.170
60.180
60.190
60.200
60.210
60.220
60.230
60.240
60.250
60.260
60.270
60.280
60.290
60.300

pu ACE / Bias

Real Power Balancing Control Performance Standard Background Document 

2.5

BAAL Based on Scheduled Frequency w/o TEC
pu ACE/Bias=BAAL@Scheduled Frequency & pu ACE/Bias=CPS1@100%

2.0

1.5

1.0

0.5

0.0

‐0.5

‐1.0
BAAL @ 60.00

CPS1=100 @ 60.00

‐1.5

‐2.0

‐2.5

Frequency (Hz)

Figure 6. BAAL Based on Scheduled Frequency w/o TEC

2.5

BAAL Based on Scheduled Frequency w/ Fast TEC

pu ACE/Bias=BAAL@Scheduled Frequency & pu ACE/Bias=CPS1@100%

2.0

1.5

1.0

0.5

0.0

‐0.5

‐1.0
BAAL @ 59.98

CPS1=100 @ 59.98

‐1.5
Fast TEC

‐2.0

‐2.5

Frequency (Hz)

Figure 5. BAAL Based o Scheduled Frequency w/ Fast TEC

BAL‐001‐1 2 ‐ Background Document 
February, 2013

1
1

59.700
59.710
59.720
59.730
59.740
59.750
59.760
59.770
59.780
59.790
59.800
59.810
59.820
59.830
59.840
59.850
59.860
59.870
59.880
59.890
59.900
59.910
59.920
59.930
59.940
59.950
59.960
59.970
59.980
59.990
60.000
60.010
60.020
60.030
60.040
60.050
60.060
60.070
60.080
60.090
60.100
60.110
60.120
60.130
60.140
60.150
60.160
60.170
60.180
60.190
60.200
60.210
60.220
60.230
60.240
60.250
60.260
60.270
60.280
60.290
60.300

pu ACE / Bias
59.700
59.710
59.720
59.730
59.740
59.750
59.760
59.770
59.780
59.790
59.800
59.810
59.820
59.830
59.840
59.850
59.860
59.870
59.880
59.890
59.900
59.910
59.920
59.930
59.940
59.950
59.960
59.970
59.980
59.990
60.000
60.010
60.020
60.030
60.040
60.050
60.060
60.070
60.080
60.090
60.100
60.110
60.120
60.130
60.140
60.150
60.160
60.170
60.180
60.190
60.200
60.210
60.220
60.230
60.240
60.250
60.260
60.270
60.280
60.290
60.300

pu ACE / Bias

Real Power Balancing Control Performance Standard Background Document 

2.5

BAAL Based on Scheduled Frequency w/ Slow TEC
pu ACE/Bias=BAAL@Scheduled Frequency & pu ACE/Bias=CPS1@100%

2.0

1.5

1.0

0.5

0.0

‐0.5

‐1.0
BAAL @ 60.02

CPS1=100 @ 60.02

‐1.5
Slow TEC

‐2.0

‐2.5

Frequency (Hz)

Figure 7. BAAL Based on Scheduled Frequency w/ Slow TEC

2.5

BAAL Based on Scheduled Frequency Summary

pu ACE/Bias=BAAL@Scheduled Frequency & pu ACE/Bias=CPS1@100%

2.0

1.5

1.0

0.5

0.0

‐0.5

‐1.0
BAAL @ 60.02

BAAL @ 60.00

‐1.5
BAAL @ 59.98

CPS1=100 @ 60.02

CPS1=100 @ 60.00

‐2.0

CPS1=100 @ 59.98

Slow TEC

‐2.5

Fast TEC

Frequency (Hz)

Figure 8. BAAL Based on Scheduled Frequency Summary

BAL‐001‐1 2 ‐ Background Document 
February, 2013

1
2

Project 2010-14.1 Balancing Authority Reliability-based
Controls - Reserves
BAL-001-2 Real Power Balancing Control Performance
Mapping Document
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 12‐
moved 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 12 
Error (ACE) divided by 10B (B is the 
month period, evaluated monthly. 
clock‐minute average of the 

Balancing Authority Area’s 
Frequency Bias) times the 
The calculation equation for CPS1 has been moved to Attachment 
corresponding clock‐minute 
1 of BAL‐001‐2. 
averages of the Interconnection’s 
Frequency Error is less than a 
specific limit. This limit ε12 is a 
constant derived from a targeted 
frequency bound (separately 
calculated for each 

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 
1 
                ‐10B 

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‐001‐2 Real Power Balancing Control Performance 
February, 2013 

2   

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 (megawatt‐
hour). 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 clock‐
for at least 90% of clock‐ten‐
replaced 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, 

Attachment 2, for the applicable Interconnection in which 
referred to as L10. 
the Balancing Authority operates. 
AVG10‐minute (ACEi ) ≤ L10 

where: 

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 
The calculation equation for BAAL is located in Attachment 2 of 
L10=1.65 Є10 
10
10  
BAL‐001‐2. 
ε10 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, 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. 

R3.  Each Balancing Authority providing  This Requirement has been 
Overlap Regulation Service shall 
moved into the BAL‐001‐2 

BAL‐001‐2 Real Power Balancing Control Performance 
February, 2013 

Attachment 1 
A Balancing Authority providing Overlap Regulation Service 

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 
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. 

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). 

This Requirement has been 
moved into the BAL‐001‐2 
Applicability Section. 

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‐001‐2 Real Power Balancing Control Performance 
February, 2013 

5   

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 
severely affect the reliability of the Bulk Power System:2 

 Emergency operations 
 Vegetation management 
 Operator personnel training 
 Protection systems and their coordination 
 Operating tools and backup facilities 
 Reactive power and voltage control 
 System modeling and data exchange 
 Communication protocol and facilities 
 Requirements to determine equipment ratings 
 Synchronized data recorders 
 Clearer criteria for operationally critical facilities 
 Appropriate use of transmission loading relief 
Guideline (2) — Consistency within a Reliability Standard

The commission expects a rational connection between the sub‐requirement Violation Risk Factor 
assignments and the main requirement Violation Risk Factor assignment. 
Guideline (3) — Consistency among Reliability Standards
1

 North American Electric Reliability Corp., 119 FERC ¶ 61,145, order on reh’g and compliance filing, 120 FERC ¶ 61,145 
(2007) (“VRF Rehearing Order”). 
2
 Id. at footnote 15.

BAL‐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 

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 
meeting the intent of 
intent of the 
the requirement. 
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‐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 per‐
violation‐per‐day basis is the “default” for penalty calculations.  

BAL‐001‐2 Real Power Balancing Control Performance 
VRF and VSL Assignments – February, 2013 

6 

VSLs for BAL-001-2 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. 

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

BAL‐001‐2 Real Power Balancing Control Performance 
VRF and VSL Assignments – February, 2013 

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. 

7 

VSLs for BAL-001-2 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 
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

R2.  

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. 

BAL‐001‐2 Real Power Balancing Control Performance 
VRF and VSL Assignments – February, 2013 

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. 

8 

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)
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:
•
•
•

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

Newsroom  •  Site Map  •  Contact NERC

Advanced Search

User Name

Ballot Results

Ballot Name: Project 2010 -14.1 BARC BAL -001-2 Initial Ballot

Password

Ballot Period: 4/16/2013 - 4/25/2013
Ballot Type: Initial

Log in

Total # Votes: 311

Register

Total Ballot Pool: 351
Quorum: 88.60 %  The Quorum has been reached

-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters

Weighted Segment
66.98 %
Vote:
Ballot Results: The drafting team will review comments received.

 Home Page
Summary of Ballot Results

Affirmative
Segment

1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals

Ballot Segment
Pool
Weight

90
10
79
24
75
54
2
6
3
8
351

#
Votes

1
0.9
1
1
1
1
0.2
0.4
0.3
0.6
7.4

#
Votes

Fraction

45
6
41
13
37
31
2
4
1
3
183

Negative
Fraction

0.662
0.6
0.651
0.722
0.661
0.66
0.2
0.4
0.1
0.3
4.956

Abstain
No
# Votes Vote

23
3
22
5
19
16
0
0
2
3
93

0.338
0.3
0.349
0.278
0.339
0.34
0
0
0.2
0.3
2.444

8
1
7
0
11
5
0
1
0
2
35

14
0
9
6
8
2
0
1
0
0
40

Individual Ballot Pool Results

Segment

1
1
1
1
1
1
1
1

Organization

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

Member

Eric Scott
Paul B Johnson
Robert Smith
John Bussman
James Armke
Kevin Smith
Christopher J Scanlon
Patricia Robertson

https://standards.nerc.net/BallotResults.aspx?BallotGUID=18a5656a-39cc-4379-a020-b95f2fc2f5b7[4/26/2013 12:39:41 PM]

Ballot

Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative

Comments

NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1

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
Consolidated Edison Co. of New York
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
El Paso Electric Company
Entergy Transmission
FirstEnergy Corp.
Florida Power & Light Co.
Gainesville Regional Utilities
Great River Energy
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
International Transmission Company Holdings
Corp
JDRJC Associates
KAMO Electric Cooperative
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Long Island Power Authority
Los Angeles Department of Water & Power
Lower Colorado River Authority
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
N.W. Electric Power Cooperative, Inc.
National Grid USA
Nebraska Public Power District
New Brunswick Power Transmission
Corporation
New York Power Authority
Northeast Missouri Electric Power Cooperative
Northern Indiana Public Service Co.
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
Santee Cooper
Seattle City Light

Donald S. Watkins
Tony Kroskey
Michael B Bax
Chang G Choi
Daniel S Langston
Jack Stamper
Paul Morland
Christopher L de Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
Dennis Malone
Oliver A Burke
William J Smith
Mike O'Neil
Richard Bachmeier
Gordon Pietsch
Ajay Garg
Martin Boisvert
Molly Devine
Michael Moltane
Jim D Cyrulewski
Walter Kenyon
Jennifer Flandermeyer
Larry E Watt
Doug Bantam
Robert Ganley
John Burnett
Martyn Turner
William Price
Nazra S Gladu
Danny Dees
Terry Harbour
Andrew J Kurriger
Mark Ramsey
Michael Jones
Cole C Brodine
Randy MacDonald
Bruce Metruck
Kevin White
Julaine Dyke
Robert Mattey
Terri Pyle
Doug Peterchuck
Jen Fiegel
Brad Chase
Daryl Hanson
Bangalore Vijayraghavan
Ryan Millard
John C. Collins
John T Walker
David Thorne
Larry D Avery
Brenda L Truhe
Laurie Williams
Kenneth D. Brown
Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Will Speer
Terry L Blackwell
Pawel Krupa

https://standards.nerc.net/BallotResults.aspx?BallotGUID=18a5656a-39cc-4379-a020-b95f2fc2f5b7[4/26/2013 12:39:41 PM]

Negative
Affirmative
Negative
Negative
Affirmative
Abstain
Negative
Affirmative

Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative

Affirmative

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Negative

NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2

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.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator

2

BC Hydro

2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3

California ISO
Electric Reliability Council of Texas, Inc.
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Ameren Services
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
City of Bartow, Florida
City of Redding
City of Tallahassee
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources, Inc.
El Paso Electric Company
Entergy
FirstEnergy Corp.
Florida Municipal Power Agency
Florida Power Corporation
Gainesville Regional Utilities
Georgia Power Company
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System

Denise Stevens
Rich Salgo
Long T Duong
Tom Hanzlik
Steven Mavis
Robert A. Schaffeld
William Hutchison
John Shaver
Noman Lee Williams
Beth Young
Howell D Scott
Tracy Sliman
John Tolo
Jonathan Appelbaum
Allen Klassen
Lloyd A Linke
Gregory L Pieper
Ken A Gardner
Venkataramakrishnan
Vinnakota
Rich Vine
Cheryl Moseley
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
stephanie monzon
Charles H. Yeung
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
Matt Culverhouse
Bill Hughes
Bill R Fowler
Charles Morgan
John Bee
Peter T Yost
Richard Blumenstock
Jose Escamilla
Michael R. Mayer
Kent Kujala
Connie B Lowe
Tracy Van Slyke
Joel T Plessinger
Cindy E Stewart
Joe McKinney
Lee Schuster
Kenneth Simmons
Danny Lindsey
Brian Glover
Paul C Caldwell
David Kiguel
Jesus S. Alcaraz
Garry Baker
Theodore J Hilmes
Charles Locke
Gregory D Woessner
Mace D Hunter
Jason Fortik

https://standards.nerc.net/BallotResults.aspx?BallotGUID=18a5656a-39cc-4379-a020-b95f2fc2f5b7[4/26/2013 12:39:41 PM]

Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Negative
Negative
Affirmative
Abstain
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Abstain
Affirmative
Negative
Affirmative
Abstain
Affirmative
Abstain
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative

NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5

Louisville Gas and Electric Co.
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
Mississippi Power
Modesto Irrigation District
Muscatine Power & Water
National Grid USA
Nebraska Public Power District
New York Power Authority
Northeast Missouri Electric Power Cooperative
NW Electric Power Cooperative, Inc.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Portland General Electric Co.
Potomac Electric Power 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.
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
Wisconsin Electric Power Marketing
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
Constellation Energy Control & Dispatch,
L.L.C.
Consumers Energy Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Georgia System Operations Corporation
Madison Gas and Electric Co.
Modesto Irrigation District
Ohio Edison Company
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
Utility Services, Inc.
Wisconsin Energy Corp.
AEP Service Corp.

Charles A. Freibert
Stephen D Pogue
Greg C. Parent
Roger Brand
Jeff Franklin
Jack W Savage
John S Bos
Brian E Shanahan
Tony Eddleman
David R Rivera
Skyler Wiegmann
David McDowell
Donald Hargrove
Blaine R. Dinwiddie
David Burke
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Thomas G Ward
Mark Yerger
Jeffrey Mueller
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
James R Keller
Michael Ibold
Herb Schrayshuen
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Reza Ebrahimian

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative

Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative

Negative

Tim Beyrle
Nicholas Zettel
John Allen

Affirmative
Affirmative

Margaret Powell

Affirmative

Tracy Goble
Russ Schneider
Frank Gaffney
Guy Andrews
Joseph DePoorter
Spencer Tacke
Douglas Hohlbaugh
Henry E. LuBean

Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative

John D Martinsen

Affirmative

Mike Ramirez
Hao Li
Steven R Wallace
Keith Morisette
Brian Evans-Mongeon
Anthony Jankowski
Brock Ondayko

Affirmative
Negative
Affirmative
Negative

https://standards.nerc.net/BallotResults.aspx?BallotGUID=18a5656a-39cc-4379-a020-b95f2fc2f5b7[4/26/2013 12:39:41 PM]

Affirmative
Negative

NERC Standards
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
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
Consolidated Edison Co. of New York
Consumers Energy Company
Dairyland Power Coop.
Detroit Edison Company
Detroit Renewable Power
Dominion Resources, Inc.
Duke Energy
Electric Power Supply Association
Entergy Services, Inc.
Exelon Nuclear
FirstEnergy Solutions
Florida Municipal Power Agency
Gainesville Regional Utilities
Great River Energy
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
NextEra Energy
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
PPL Generation LLC
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.
South Feather Power Project
Southern California Edison Company
Southern Company Generation
Tacoma Power

Sam Dwyer
Scott Takinen
Matthew Pacobit
Clement Ma
Mike D Kukla
Francis J. Halpin
Shari Heino
Jeanie Doty
Paul A. Cummings
Karen Webb
Steve Rose
Michael Shultz
Wilket (Jack) Ng
David C Greyerbiehl
Tommy Drea
Alexander Eizans
Marcus Ellis
Mike Garton
Dale Q Goodwine
John R Cashin
Tracey Stubbs
Mark F Draper
Kenneth Dresner
David Schumann
Karen C Alford
Preston L Walsh
Marcela Y Caballero
John J Babik
Brett Holland
James M Howard
Dennis Florom
Kenneth Silver
Karin Schweitzer
S N Fernando
David Gordon
Steven Grego
Neil D Hammer
Mike Avesing
Don Schmit
Wayne Sipperly
Allen D Schriver
William O. Thompson
Bernard Johnson
Leo Staples
Mahmood Z. Safi
Richard K Kinas
Bonnie Marino-Blair
Roland Thiel
Matt E. Jastram
Tim Hattaway
Annette M Bannon
Tim Kucey

Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Abstain
Abstain
Negative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Abstain
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative

Michiko Sell
Lynda Kupfer
Susan Gill-Zobitz
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Edward Magic
Kathryn Zancanella
Denise Yaffe
William D Shultz
Chris Mattson

https://standards.nerc.net/BallotResults.aspx?BallotGUID=18a5656a-39cc-4379-a020-b95f2fc2f5b7[4/26/2013 12:39:41 PM]

Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Negative

NERC Standards
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
7
7

Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
U.S. Bureau of Reclamation
Westar Energy
Wisconsin Electric Power Co.
Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
APS
Associated Electric Cooperative, Inc.
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Con Edison Company of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy
El Paso Electric Company
Entergy Services, Inc.
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Energy
Manitoba Hydro
Modesto Irrigation District
Muscatine Power & Water
New York Power Authority
Northern Indiana Public Service Co.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
Power Generation Services, Inc.
Powerex Corp.
PPL EnergyPlus LLC
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
Southern California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
EnerVision, Inc.
Steel Manufacturers Association

RJames Rocha
Scott M. Helyer
David Thompson
Mark Stein
Melissa Kurtz
Martin Bauer
Bryan Taggart
Linda Horn
Liam Noailles
Edward P. Cox
Jennifer Richardson
Randy A. Young
Brian Ackermann
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Shannon Fair
David Balban
David J Carlson
Louis S. Slade
Greg Cecil
Tony Soto
Terri F Benoit
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Packer
Brenda Hampton
Blair Mukanik
James McFall
John Stolley
Saul Rojas
Joseph O'Brien
Douglas Collins
Kelly Cumiskey
Carol Ballantine
Ty Bettis
Stephen C Knapp
Daniel W. O'Hearn
Elizabeth Davis
Peter Dolan
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
Kenn Backholm
Lujuanna Medina

Affirmative
Abstain
Affirmative
Negative
Affirmative

John J. Ciza

Affirmative

Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson

Negative
Affirmative
Affirmative
Negative

Peter H Kinney
David F Lemmons
Thomas W Siegrist
James Brew

https://standards.nerc.net/BallotResults.aspx?BallotGUID=18a5656a-39cc-4379-a020-b95f2fc2f5b7[4/26/2013 12:39:41 PM]

Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Abstain
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative

Negative
Affirmative
Affirmative
Affirmative

NERC Standards
8
8
8
8
8
8
9
9
9
10
10
10
10
10
10
10
10

Self
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
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council

Roger C Zaklukiewicz
Robert Blohm
Edward C Stein
Debra R Warner
Howard F. Illian
Terry Volkmann

Affirmative
Affirmative
Affirmative
Abstain
Affirmative

Donald Nelson

Affirmative

Norman Harryhill

Negative

Diane J. Barney

Negative

Linda Campbell
Russel Mountjoy
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Donald G Jones
Steven L. Rueckert

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https://standards.nerc.net/BallotResults.aspx?BallotGUID=18a5656a-39cc-4379-a020-b95f2fc2f5b7[4/26/2013 12:39:41 PM]

Abstain
Affirmative
Affirmative
Abstain
Negative
Negative
Negative
Affirmative

Non-binding Poll Results
Project 2010-14.1 BAL-001-2

Non-binding Poll Results

Non-binding Poll
Project 2010-14.1 BARC Non-binding Poll BAL-001-2
Name:
Poll Period: 4/16/2013 - 4/25/2013
Total # Opinions: 283
Total Ballot Pool: 329
86.02% of those who registered to participate provided an opinion or an
Summary Results: abstention; 73.19% of those who provided an opinion indicated support
for the VRFs and VSLs.
Individual Ballot Pool Results

Segment

Organization

1
1
1
1
1

1
1
1

Ameren Services
American Electric Power
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Austin Energy
Balancing Authority of Northern
California
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

1
1
1
1
1
1
1
1
1
1
1

CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Duke Energy Carolina
El Paso Electric Company
Entergy Transmission
FirstEnergy Corp.
Florida Power & Light Co.
Gainesville Regional Utilities
Great River Energy
Hydro One Networks, Inc.

1
1
1
1
1
1

Member
Eric Scott
Paul B Johnson
Robert Smith
John Bussman
James Armke
Kevin Smith
Patricia Robertson
Donald S. Watkins
Tony Kroskey
Michael B Bax
Chang G Choi
Daniel S Langston
Jack Stamper
Paul Morland
Christopher L de
Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Douglas E. Hils
Dennis Malone
Oliver A Burke
William J Smith
Mike O'Neil
Richard Bachmeier
Gordon Pietsch
Ajay Garg

Opinions
Abstain
Abstain
Affirmative
Negative
Abstain
Abstain
Abstain
Affirmative
Affirmative
Negative
Negative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Abstain

Comments

1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1

Hydro-Quebec TransEnergie
Idaho Power Company
International Transmission Company
Holdings Corp
JDRJC Associates
KAMO Electric Cooperative
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Long Island Power Authority
Los Angeles Department of Water &
Power
Lower Colorado River Authority
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
N.W. Electric Power Cooperative, Inc.
National Grid USA
Nebraska Public Power District
New Brunswick Power Transmission
Corporation
New York Power Authority
Northeast Missouri Electric Power
Cooperative
Northern Indiana Public Service Co.
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
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.

Non-binding Poll Results: BAL-001-2

Martin Boisvert
Molly Devine

Affirmative
Affirmative

Michael Moltane

Abstain

Jim D Cyrulewski
Walter Kenyon
Jennifer Flandermeyer
Larry E Watt
Doug Bantam
Robert Ganley

Affirmative
Affirmative

Affirmative

John Burnett
Martyn Turner
William Price
Nazra S Gladu
Danny Dees
Terry Harbour
Andrew J Kurriger
Mark Ramsey
Michael Jones
Cole C Brodine

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

Randy MacDonald

Abstain

Bruce Metruck

Abstain

Affirmative
Negative
Abstain

Kevin White

Affirmative

Julaine Dyke
Robert Mattey
Terri Pyle
Doug Peterchuck
Jen Fiegel
Brad Chase
Daryl Hanson
Bangalore Vijayraghavan
Ryan Millard
John C. Collins
John T Walker
Larry D Avery
Brenda L Truhe
Laurie Williams
Kenneth D. Brown
Denise M Lietz
Tim Kelley
Robert Kondziolka
Will Speer
Terry L Blackwell
Pawel Krupa
Denise Stevens
Rich Salgo

Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Abstain
Abstain
Negative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Abstain
Affirmative
Abstain
Affirmative
Negative
Affirmative
Abstain

2

1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3

Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southern California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative,
Inc.
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.

Long T Duong
Tom Hanzlik
Steven Mavis
Robert A. Schaffeld
William Hutchison
John Shaver

Noman Lee Williams
Beth Young
Howell D Scott
Tracy Sliman
John Tolo
Jonathan Appelbaum
Allen Klassen
Lloyd A Linke
Gregory L Pieper
Venkataramakrishnan
BC Hydro
Vinnakota
California ISO
Rich Vine
Electric Reliability Council of Texas, Inc. Cheryl Moseley
Midwest ISO, Inc.
Marie Knox
New Brunswick System Operator
Alden Briggs
New York Independent System Operator Gregory Campoli
PJM Interconnection, L.L.C.
stephanie monzon
Southwest Power Pool, Inc.
Charles H. Yeung
AEP
Michael E Deloach
Alabama Power Company
Robert S Moore
Ameren Services
Mark Peters
APS
Steven Norris
Associated Electric Cooperative, Inc.
Chris W Bolick
Avista Corp.
Scott J Kinney
BC Hydro and Power Authority
Pat G. Harrington
Bonneville Power Administration
Rebecca Berdahl
Central Electric Power Cooperative
Adam M Weber
City of Austin dba Austin Energy
Andrew Gallo
City of Bartow, Florida
Matt Culverhouse
City of Redding
Bill Hughes
City of Tallahassee
Bill R Fowler
Colorado Springs Utilities
Charles Morgan
Consolidated Edison Co. of New York
Peter T Yost
Consumers Energy
Richard Blumenstock
CPS Energy
Jose Escamilla
Detroit Edison Company
Kent Kujala
Dominion Resources, Inc.
Connie B Lowe
El Paso Electric Company
Tracy Van Slyke
Entergy
Joel T Plessinger
FirstEnergy Corp.
Cindy E Stewart
Florida Municipal Power Agency
Joe McKinney

Non-binding Poll Results: BAL-001-2

Affirmative
Affirmative
Affirmative
Negative
Negative
Abstain
Negative
Affirmative
Affirmative
Negative
Negative
Abstain
Affirmative
Negative
Affirmative
Abstain
Abstain
Abstain
Abstain
Abstain
Affirmative
Abstain
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Negative
Abstain
Negative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Negative
Affirmative

3

3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3

Florida Power Corporation
Gainesville Regional Utilities
Georgia Power Company
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Louisville Gas and Electric Co.
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
Mississippi Power
Modesto Irrigation District
Muscatine Power & Water
National Grid USA
Nebraska Public Power District
New York Power Authority
Northeast Missouri Electric Power
Cooperative
NW Electric Power Cooperative, Inc.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Portland General Electric Co.
Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
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.

Non-binding Poll Results: BAL-001-2

Lee Schuster
Kenneth Simmons
Danny Lindsey
Brian Glover
Paul C Caldwell
David Kiguel
Jesus S. Alcaraz
Garry Baker
Theodore J Hilmes
Charles Locke
Gregory D Woessner
Mace D Hunter
Jason Fortik
Charles A. Freibert
Stephen D Pogue
Greg C. Parent
Roger Brand
Jeff Franklin
Jack W Savage
John S Bos
Brian E Shanahan
Tony Eddleman
David R Rivera

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain

Skyler Wiegmann

Affirmative

David McDowell
Donald Hargrove
Blaine R. Dinwiddie
David Burke
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Thomas G Ward
Jeffrey Mueller
Erin Apperson
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

Affirmative
Affirmative
Negative
Negative
Abstain
Abstain
Negative
Abstain
Abstain
Affirmative
Negative
Abstain
Abstain
Abstain
Affirmative
Affirmative
Negative

Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Abstain
Abstain

Affirmative
Negative

4

3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5

Tennessee Valley Authority
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
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
Consumers Energy Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Georgia System Operations Corporation
Madison Gas and Electric Co.
Modesto Irrigation District
Ohio Edison Company
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
Utility Services, Inc.
Wisconsin Energy Corp.
AEP Service Corp.
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
Consolidated Edison Co. of New York
Consumers Energy Company
Dairyland Power Coop.
Detroit Edison Company

Non-binding Poll Results: BAL-001-2

Ian S Grant
Janelle Marriott
Bo Jones
James R Keller
Michael Ibold
Herb Schrayshuen
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Reza Ebrahimian

Abstain
Negative
Negative
Abstain
Affirmative
Affirmative

Abstain

Tim Beyrle
Nicholas Zettel
John Allen
Tracy Goble
Russ Schneider
Frank Gaffney
Guy Andrews
Joseph DePoorter
Spencer Tacke
Douglas Hohlbaugh

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Negative

Henry E. LuBean
John D Martinsen

Affirmative

Mike Ramirez
Hao Li
Steven R Wallace
Keith Morisette
Brian Evans-Mongeon
Anthony Jankowski
Brock Ondayko
Sam Dwyer
Scott Takinen
Matthew Pacobit
Clement Ma

Abstain
Negative
Affirmative
Negative

Mike D Kukla
Francis J. Halpin
Shari Heino
Jeanie Doty
Paul A. Cummings
Karen Webb
Steve Rose
Michael Shultz
Wilket (Jack) Ng
David C Greyerbiehl
Tommy Drea
Alexander Eizans

Affirmative
Abstain
Abstain
Affirmative
Abstain
Negative
Affirmative
Negative
Abstain
Affirmative
Negative
Abstain
Abstain
Negative
Affirmative
Affirmative
Affirmative

5

5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5

Dominion Resources, Inc.
Duke Energy
Electric Power Supply Association
Entergy Services, Inc.
FirstEnergy Solutions
Florida Municipal Power Agency
Gainesville Regional Utilities
Great River Energy
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water &
Power
Manitoba Hydro
Massachusetts Municipal Wholesale
Electric Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
NextEra Energy
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
PPL Generation LLC
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.
South Feather Power Project
Southern California Edison Company
Southern Company Generation
Tacoma Power

Non-binding Poll Results: BAL-001-2

Mike Garton
Dale Q Goodwine
John R Cashin
Tracey Stubbs
Kenneth Dresner
David Schumann
Karen C Alford
Preston L Walsh
Marcela Y Caballero
John J Babik
Brett Holland
James M Howard
Dennis Florom

Abstain
Affirmative
Abstain
Negative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative

Kenneth Silver

Abstain

S N Fernando

Affirmative

David Gordon

Abstain

Steven Grego
Neil D Hammer
Mike Avesing
Don Schmit
Wayne Sipperly
Allen D Schriver
William O. Thompson
Bernard Johnson
Leo Staples
Mahmood Z. Safi
Richard K Kinas
Bonnie Marino-Blair
Roland Thiel
Matt E. Jastram
Tim Hattaway
Annette M Bannon
Tim Kucey

Affirmative
Affirmative
Negative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Negative
Affirmative
Abstain

Michiko Sell
Lynda Kupfer
Susan Gill-Zobitz
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Edward Magic
Kathryn Zancanella
Denise Yaffe
William D Shultz
Chris Mattson

Abstain
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative

6

5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6

Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
U.S. Bureau of Reclamation
Wisconsin Electric Power Co.
Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
APS
Associated Electric Cooperative, Inc.
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Con Edison Company of New York
Duke Energy
Entergy Services, Inc.
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water &
Power
Luminant Energy
Manitoba Hydro
Modesto Irrigation District
Muscatine Power & Water
New York Power Authority
Northern Indiana Public Service Co.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
Power Generation Services, Inc.
Powerex Corp.
PPL EnergyPlus LLC
PSEG Energy Resources & Trade LLC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper

Non-binding Poll Results: BAL-001-2

RJames Rocha
Scott M. Helyer
David Thompson
Mark Stein
Melissa Kurtz
Martin Bauer
Linda Horn
Liam Noailles
Edward P. Cox
Jennifer Richardson
Randy A. Young
Brian Ackermann
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Shannon Fair
David Balban
Greg Cecil
Terri F Benoit
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp

Affirmative
Abstain
Abstain
Abstain
Affirmative

Abstain
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Abstain
Affirmative

Brad Packer
Brenda Hampton
Blair Mukanik
James McFall
John Stolley
Saul Rojas
Joseph O'Brien
Douglas Collins
Kelly Cumiskey
Carol Ballantine
Ty Bettis
Stephen C Knapp
Daniel W. O'Hearn
Elizabeth Davis
Peter Dolan
Diane Enderby
Steven J Hulet
Michael Brown

Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Negative
Affirmative
Abstain
Abstain
Affirmative
Affirmative

7

6
6
6
6
6
6
6
6
6
6
7
7
8
8
8
8
8
8
9
9
10
10
10
10
10
10
10

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
EnerVision, Inc.
Steel Manufacturers Association

Self
Energy Mark, Inc.
Volkmann Consulting, Inc.
Commonwealth of Massachusetts
Department of Public Utilities
Gainesville Regional Utilities
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council

Non-binding Poll Results: BAL-001-2

Dennis Sismaet
Trudy S. Novak
Kenn Backholm
Lujuanna Medina

Negative
Affirmative
Affirmative
Affirmative

John J. Ciza

Affirmative

Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson

Negative
Affirmative
Abstain
Negative

Peter H Kinney

Negative

Thomas W Siegrist
James Brew
Roger C Zaklukiewicz
Robert Blohm
Edward C Stein
Debra R Warner
Howard F. Illian
Terry Volkmann

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative

Donald Nelson

Affirmative

Norman Harryhill
Linda Campbell
Russel Mountjoy
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Donald G Jones
Steven L. Rueckert

Negative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Abstain

8

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 + 3Ԑ1i should be changed to Fs + 4Ԑ1i
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.

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

The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities
Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

1.

Group

Guy Zito

Additional Member

2

3

4

5

Northeast Power Coordinating Council

Additional Organization

Alan Adamson

New York State Reliability Council, LLC

NPCC 10

2.

Carmen Agavriloai

Independent Electricity System Operator

NPCC 2

3.

Greg Campoli

New York Independent System Operator

NPCC 2

4.

Sylvain Clermont

Hydro-Quebec TransEnergie

NPCC 1

5.

Chris de Graffenried Consolidated Edison Co. of New York, Inc. NPCC 1

6.

Gerry Dunbar

Northeast Power Coordinating Council

NPCC 10

7.

Mike Garton

Dominion Resources Services, Inc.

NPCC 5

8.

Peter Yost

Consolidated Edison Co. of New York, Inc. NPCC 3

9.

Michael Jones

National Grid

NPCC 1

10. David Kiguel

Hydro One Networks Inc.

NPCC 1

11. Christina Koncz

PSEG Power LLC

NPCC 5

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

7

8

9

10

X

Region Segment Selection

1.

6

4

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

12. Randy MacDonald

New Brunswick Power Transmission

NPCC 9

13. Bruce Metruck

New York Power Authority

NPCC 6

14. Silvia Parada Mitchell NExtEra Energy, LLC

NPCC 5

15. Lee Pedowicz

Northeast Power Coordinating Council

NPCC 10

16. Robert Pellegrini

The United Illuminating Company

NPCC 1

17. Si-Truc Phan

Hydro-Quebec TransEnergie

NPCC 1

18. David Ramkalawan

Ontario Power Generation, Inc.

NPCC 5

19. Brian Robinson

Utility Services

NPCC 8

20. Brian Shanahan

National Grid

NPCC 1

21. Wayne Sipperly

New York Power Authority

NPCC 5

22. Donald Weaver

New Brunswick System Operator

NPCC 2

23. Ben Wu

Orange and Rockland Utilities

NPCC 1

2.

paul haase

Group

seattle city light

2

3

4

5

6

X

X

X

X

X

X

X

X

X

X

7

8

9

10

Additional Member Additional Organization Region Segment Selection
1.

pawel krupa

seattle city light

WECC 1

2.

dana wheelock

seattle city light

WECC 3

3.

hao li

seattle city light

WECC 4

4.

mike haynes

seattle city light

WECC 5

5.

dennis sismaet

seattle city light

WECC 6

3.

Russel MountjoySecretary

Group

MRO NERC Standards Review Forum

Additional Member Additional Organization Region Segment Selection
1.

Alice Ireland

Xcel Energy

MRO

1, 3, 5

2.

Joseph DePoorter

MGE

MRO

3, 4, 5, 6

3.

Dan Inman

MPC

MRO

1, 3, 5, 6

4.

Dave Rudolf

BEPC

MRO

1, 3, 5, 6

5.

Jodi Jensen

WAPA

MRO

1, 6

6.

Ken Goldsmith

ALTW

MRO

4

7.

Lee Kittleson

OTP

MRO

1, 3, 5

8.

Marie Knowx

MISO

MRO

2

9.

Mike Brytowski

GRE

MRO

1, 3, 5, 6

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

5

X

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

10. Scott Bos

MPW

MRO

1, 3, 5, 6

11. Scott Nickels

RPU

MRO

4

12. Terry Harbour

MEC

MRO

1, 3, 5, 6

13. Tom Breene

WPS

MRO

3, 4, 5, 6

14. Tony Eddleman

NPPD

MRO

1, 3, 5

4.

Robert Rhodes

Group
Additional Member

Sunflower Electric Power Corporation SPP

1

2. Bo Jones

Westar Energy

SPP

1, 3, 5, 6

3. Tiffany Lake

Westar Energy

SPP

1, 3, 5, 6

4. Jerry McVey

Sunflower Electric Power Corporation SPP

1

5. Kevin Nincehelser

Westar Energy

SPP

1, 3, 5, 6

6. Bryan Taggart

Westar Energy

SPP

1, 3, 5, 6

Group

Stuart Goza

4

5

6

Region Segment Selection

1. Allan George

5.

3

X

SPP Standards Review Group

Additional Organization

2

SERC OC Standards Review Group

X

X

X

X

Additional Member Additional Organization Region Segment Selection
1.

Jeff Harrison

AECI

SERC

1, 3, 5, 6

2.

Ray Phillips

AMEA

SERC

4

3.

David Jendras

Ameren

SERC

1, 3

4.

Kevin Johnson

Big Rivers

SERC

1

5.

Colby Brett Bellville Duke

SERC

1, 3, 5, 6

6.

Mike Lowman

Duke

SERC

1, 3, 5, 6

7.

Tom Pruitt

Duke

SERC

1, 3, 5, 6

8.

Jim Case

Enteregy

SERC

1, 3, 6

9.

Phil Whitmer

Georgia Power Company SERC

3

10. Wayne Van Liere

LGE-KU

SERC

1, 3, 5, 6

11. Terry Bilke

MISO

SERC

2

12. Brad Gordon

PJM

SERC

2

13. Bill Thigpen

PowerSouth

SERC

1, 5

14. Tim Hattaway

Power South

SERC

1, 5

15. Sammy Roberts

Progress Energy

SERC

1, 3, 5, 6

16. Troy Blalock

SCE&G

SERC

1, 3, 5, 6

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

6

7

8

9

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

17. Glenn Stephens

SCPSA

SERC

1, 3, 5, 6

18. Rene Free

SCPSA

SERC

1, 3, 5, 6

19. Tom Abrams

SCPSA

SERC

1, 3, 5, 6

20. John Rembold

SIPC

SERC

1

21. Cindy Martin

Southern

SERC

1, 5

22. Jimmy Cummings

Southern

SERC

1, 5

23. Jimmy Cummings

Southern

SERC

1, 5

24. Randy Hubbert

Southern

SERC

1, 5

25. Kelly Casteel

TVA

SERC

1, 4, 5, 6

6.

Greg Rowland

Group

Duke Energy

2

3

4

5

6

X

X

X

X

X

X

X

X

X

X

Additional Member Additional Organization Region Segment Selection
1. Doug Hils

Duke Energy

RFC

1

2. Lee Schuster

Duke Energy

FRCC

3

3. Dale Goodwine

Duke Energy

SERC

5

4. Greg Cecil

Duke Energy

RFC

6

7.

Group

Brent Ingebrigtson

Additional Member

PPL NERC Registered Affiliates

Additional Organization

Region Segment Selection

1. Brenda Truhe

PPL Electric Utilities Corporation

RFC

1

2. Annette Bannon

PPL Generation, LLC on behalf of Supply NERC Registered Affiliates RFC

5

3.

WECC 5

4. Elizabeth Davis

8.

PPL EnergyPlus, LLC

Group

MRO

Larry Raczkowski

6

X

FirstEnergy

X

X

Additional Member Additional Organization Region Segment Selection
1. William Smith

FirstEnergy Corp

RFC

1

2. Cindy Stewart

FirstEnergy Corp

RFC

3

3. Doug Hohlbaugh

Ohio Edison

RFC

4

4. Ken Dresner

FirstEnergy Solutions

RFC

5

5. Kevin Querry

FirstEnergy Solutions

RFC

6

9.

Group

Lloyd A. Linke

Additional Member

Western Area Power Administration
Additional Organization

1. Western Area Power Administration Upper Great Plains Region

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

X

X

Region Segment Selection
MRO

1, 6

7

7

8

9

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2. Western Area Power Administration Rocky Mouontain Region

WECC 1, 6

3. Western Area Power Administration Desert Southwest Region

WECC 1, 6

4. Western Area Power Administration Sierra Nevada Region

WECC 1, 6

2

3

4

5

6

5. Western Area Power Administration Colorado River Storage Project WECC 6

10.

Group

Marie Knox

X

MISO Standards Collaborators

Additional Member Additional Organization Region Segment Selection
1. Joe O'Brein

11.

NIPSCO

Group

RFC

H. Steven Myers

6

X

ERCOT

Additional Member Additional Organization Region Segment Selection
1. Matt Morais

ERCOT

ERCOT 2

2. Sandip Sharma

ERCOT

ERCOT 2

3. Matt Stout

ERCOT

ERCOT 2

4. Ken McIntyre

ERCOT

ERCOT 2

5. Stephen Solis

ERCOT

ERCOT 2

6. Vann Weldon

ERCOT

ERCOT 2

7. Jeff Healy

ERCOT

ERCOT 2

12.

Group

Jason Marshall

Additional Member

Additional Organization

Region Segment Selection

1. Megan Wagner

Sunflower Electric Power Corporation SPP

2. John Shaver

Arizona Electric Power Cooperative

3. John Shaver

Southwest Transmission Cooperative WECC 1

4. Michael Brytowski

Great River Energy

13.

Group

X

ACES Standards Collaborators

WECC 4, 5
MRO

Dennis Chastain

1

1, 3, 5, 6

Tennessee Valley Authority

X

X

X

X

X

X

X

Additional Member Additional Organization Region Segment Selection
1. DeWayne Scott

SERC

1

2. Ian Grant

SERC

3

3. David Thompson

SERC

5

4. Marjorie Parsons

SERC

6

14.

Group

Terri Pyle

Oklahoma Gas & Electric

Additional Member Additional Organization Region Segment Selection

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

8

7

8

9

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

1. Terri Pyle

Oklahoma Gas & Electric SPP

1

2. Donald Hargrove

Oklahoma Gas & Electric SPP

3

3. Leo Staples

Oklahoma Gas & Electric SPP

5

15.

Group

Brenda Hampton

Additional Member
1. Rick Terrill

16.

2

3

4

5

X

Luminant

Additional Organization

6

Region Segment Selection

Luminant Generation Company LLC ERCOT 5

Group

Terry Bilke

X

IRC-SRC

Additional Member Additional Organization Region Segment Selection
1. Stephanie Monzon

PJM

RFC

2. Ben Li

IESO

NPCC 2

2

3. Kathleen Goodman ISONE

NPCC 2

4. Charles Yeung

SPP

SPP

5. Ali Miremadi

CAISO

WECC 2

17.

Group

Patricia Robertson

Additional Member

2

BC Hydro and Power Authority

Additional Organization

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

Region Segment Selection

1. Venkataramakrishnan Vinnakota BC Hydro and Power Authority WECC 2
2. Pat G. Harrington

BC Hydro and Power Authority WECC 3

3. Clement Ma

BC Hydro and Power Authority WECC 5

18.

Group

Jamison Dye

Bonneville Power Administration

Additional Member Additional Organization Region Segment Selection
1. Bart McManus

WECC 1

2. Fran Halpin

WECC 5

3. David Kirsch

WECC 1

4. Ayodele Idowu

WECC 1

5. Pam VanCalcar

WECC 5

6. Don Watkins

WECC 1

19.

Individual

Salt River Project

Individual

Bob Steiger
Janet Smith, Regulatory
Affairs Supervisor

Individual

Ryan Millard

PacifiCorp

20.
21.

Arizona Public Service Company

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

9

7

8

9

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

22.

Individual

Stephanie Monzon

2

3

4

5

Individual

Pamela R. Hunter

24.

Individual

Dan O'Hearn

Powerex Corp.

25.

Individual

Tom Siegrist

EnerVision, Inc.

26.

Individual

John Tolo

Tucson Electric Power Co

X

27.

Individual

Rich Hydzik

Avista

X

X

X

28.

Individual

Nazra Gladu

Manitoba Hydro

X

X

X

29.

Individual

Anthony Jablonski

ReliabilityFirst

30.

Individual

Joe Tarantino

SMUD

X

31.

Individual

Jim Cyrulewski

JDRJC Associates LLC

X

32.

Individual

Greg Travis

Idaho Power Company

X

Individual
34. Individual

Michael Falvo
Howard F. Illian

Independent Electricity System Operator
Energy Mark, Inc.

35.

Individual

Don Schmit

Nebraska Public Power District

36.

Individual

Kenneth A Goldsmith

Alliant Energy

37.

Individual

Andrew Gallo

City of Austin dba Austin Energy

X

X

38.

Individual

Angela P Gaines

Portland General Electric Company

X

39.

Individual

Kathleen Goodman

ISO New England Inc.

40.

Individual

Thad Ness

American Electric Power

41.

Individual

John Seelke

Public Service Enterprise Group

42.

Individual

Linda Horn

Wisconsin Electric Power Company

43.

Individual

Don Jones

Texas Reliability Entity

33.

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

7

8

9

10

X

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

23.

6

X

X

X

X

X
X

X
X

X

X

X

X

X
X
X

X

X
X
X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X
X

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

44.

2

3

4

5

6

Oliver Burke

Entergy Services, Inc. (Transmission)

X

X

X

X

Individual
46. Individual

Brian Murphy
Robert Blohm

NextEra Energy
Keen Resources Ltd.

X

X

X

X

47.

Individual

Bill Fowler

City of Tallahassee

48.

Individual

Karen Webb

City of Tallahassee

49.

Individual

Scott Langston

City of Tallahassee

X

50.

Individual

Christopher Wood

Platte River Power Authority

X

51.

Individual

Spencer Tacke

Modesto Irrigation District

52.

Individual

NYISO

Individual

Gregory Campoli
John Bee on Behalf or
Exelon and its Affiliates

54.

Individual

Keith Morisette

55.

Individual

Alice Ireland

Individual

45.

53.

8

X
X
X
X
X

X

X

X

X

X
X

X

Tacoma Power

X

X

Xcel Energy

X

X

X

Exelon

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

7

X

X

X

X

X

11

9

10

If you support the comments submitted by another entity and would like to indicate you agree with their comments, please select
"agree" below and enter the entity's name in the comment section (please provide the name of the organization, trade association,
group, or committee, rather than the name of the individual submitter).

Summary Consideration:

Organization

Supporting Comments of “Entity Name”

Luminant

Electric Reliability Council of Texas (ERCOT)

City of Austin dba Austin Energy

ERCOT

JDRJC Associates LLC

Midwest ISO

Wisconsin Electric Power Company

Midwest ISO

FirstEnergy

MISO

Alliant Energy

MRO NSRF

NYISO

Northeast Power Coordinating Council

Public Service Enterprise Group

PJM Interconnection

Platte River Power Authority

Public Service Company of Colorado (Xcel Energy)

Tennessee Valley Authority

SERC OC Standards Review Group

Entergy Services, Inc. (Transmission)

SERC OC Standards Review Group

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

12

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.

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.
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.
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.
The majority of the commenters provided typographical corrections that needed to be made to the standard and its associated
documents.

Organization

Yes or No

ACES Standards Collaborators

No

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Question 1 Comment
(1) How does this standard “specifically preclude general improvements

13

Organization

Yes or No

Question 1 Comment
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

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

14

Organization

Yes or No

Question 1 Comment
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

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

15

Organization

Yes or No

Question 1 Comment
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.

Response: The BARC standards drafting team believes that this answer does not apply to the proposed BAL-001-2 standard.
Duke Energy

No

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

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
16

Organization

Yes or No

Question 1 Comment
definition of RRSG.

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

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.

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.
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 BAL-004-WECC-01.

Response: The SDT appreciates your comments. The intent was to create a standard term for ACE that was flexible enough to
Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

17

Organization

Yes or No

Question 1 Comment

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.
Bonneville Power Administration

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.

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.
Northeast Power Coordinating Council

No

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

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
18

Organization

Yes or No

Question 1 Comment
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.

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
Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

19

Organization

Yes or No

Question 1 Comment

SDT has modified the definition to address concerns raised by the industry.
The Regulating Reserve Sharing Group will be added to the NERC Compliance Registry prior to this standard becoming effective.
ISO New England Inc.

No

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

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

20

Organization

Yes or No

Question 1 Comment
through the FMWG.

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.
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.
The Regulating Reserve Sharing Group will be added to the NERC Compliance Registry prior to this standard becoming effective.
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.

Response: The SDT appreciates your comments. The SDT has developed these terms for the following reasons.
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.
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.
Modesto Irrigation District

No

This concept violates the very definition of a balancing authority
(control area).

Response: The SDT appreciates your comments. Unfortunately, the SDT would need additional information to provide a
response to your comment.
Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

21

Organization

Yes or No

Independent Electricity System
Operator

No

Question 1 Comment
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.

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.
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.
The Regulating Reserve Sharing Group will be added to the NERC Compliance Registry prior to this standard becoming effective.
MRO NERC Standards Review Forum

No

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

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
22

Organization

Yes or No

Question 1 Comment
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.

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 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.
The Regulating Reserve Sharing Group will be added to the NERC Compliance Registry prior to this standard becoming effective.
MISO Standards Collaborators

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.

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
Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

23

Organization

Yes or No

Question 1 Comment

a standard.
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.
The Regulating Reserve Sharing Group will be added to the NERC Compliance Registry prior to this standard becoming effective.
IRC-SRC

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.

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 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.
The Regulating Reserve Sharing Group will be added to the NERC Compliance Registry prior to this standard becoming effective.
SMUD

No
Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

While the definitions are acceptable, terminology within the standards

24

Organization

Yes or No

Question 1 Comment
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.

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.
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)

Response: The SDT appreciates your comments.
1) The SDT has corrected this error.
2) The SDT has corrected this and is now using a single term.
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’

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

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Organization

Yes or No

Question 1 Comment
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 ‘regulatingreserve’ 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’.

Response: Thank you for your comments.
1)
2)
3)
4)
5)
6)

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.
Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

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Organization

Yes or No

Question 1 Comment

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.
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.

Response: The SDT appreciates your comments. The SDT has corrected this and is now using a single term.
SERC OC Standards Review Group

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.”

Response: The SDT appreciates your comments. The SDT is trying to provide a consistent measure of ACE to apply across all
standards.
SPP Standards Review Group

Yes

PPL NERC Registered Affiliates

Yes

ERCOT

Yes

Oklahoma Gas & Electric

Yes

Salt River Project

Yes

Arizona Public Service Company

Yes

PacifiCorp

Yes

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Organization

Yes or No

Question 1 Comment

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
EnerVision, Inc.

Yes

Tucson Electric Power Co

Yes

Avista

Yes

Idaho Power Company

Yes

Energy Mark, Inc.

Yes

Portland General Electric Company

Yes

Keen Resources Ltd.

Yes

City of Tallahassee

Yes

City of Tallahassee

Yes

City of Tallahassee

Yes

Tacoma Power

Yes

Xcel Energy

Yes

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28

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.

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.
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.
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.
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
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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.
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.
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 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.

Organization

Yes or No

ACES Standards Collaborators

No

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

Question 2 Comment
(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

30

Organization

Yes or No

Question 2 Comment
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.

Response: Thank you for your comment. Unfortunately, the comment you provided does not appear to address draft Standard
BAL-001-2.
Bonneville Power Administration

No

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

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
31

Organization

Yes or No

Question 2 Comment
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 offnominal 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

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Organization

Yes or No

Question 2 Comment
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.

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Organization

Yes or No

Question 2 Comment
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.

Response: Thank you for your comments.
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
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Organization

Yes or No

Question 2 Comment

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
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Organization

Yes or No

Question 2 Comment

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.
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

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Organization

Yes or No

Question 2 Comment
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.

Response: Thank you for your comments.
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
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Organization

Yes or No

Question 2 Comment

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.
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.

Response: Thank you for your comments.
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.
seattle city light

No

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

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
38

Organization

Yes or No

Question 2 Comment
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
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.
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

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Organization

Yes or No

Question 2 Comment
frequency.

Response: Thank you for your comments.
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 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.
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.

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Organization

Yes or No

Question 2 Comment

Response: Thank you for your comments.
The calculation of CPS1 would be the same whether or not a BA participates in a RRSG.
The SDT included the possibility of active versus inactive status for the potential of events such as, but not limited to telemetry
failure.
City of Tallahassee

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.

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.
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

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Organization

Yes or No

Question 2 Comment
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.

Response: Thank you for your comments.
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
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Organization

2.

3.

4.
5.

Yes or No

Question 2 Comment

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.

NYISO

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.

Response: Thank you for your comments.

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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.
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 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.
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 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.
City of Tallahassee

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.

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.
Avista

No

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

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

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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

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Question 2 Comment
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.
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

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Question 2 Comment
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.

Response: Thank you for your comments.
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
Consideration of Comments: Project 2010-14.1
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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.
City of Tallahassee

No

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

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
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Team analyzed the potential timeframes for implementation. TAL
contends that 12 months would be more appropriate.

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.
Northeast Power Coordinating
Council

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.

Response: Thank you for your comments.
The SDT has eliminated the term RRSG Reporting ACE.
The calculation of CPS1 would be the same whether or not a BA participates in a RRSG.
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 SDT has added clarifying language to Attachment 2 on how bad data is handled for BAAL.
ISO New England Inc.

No

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

We do not see the need to create the two new terms (RRSG and RRSG

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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.

Response: Thank you for your comments.
The SDT has eliminated the term RRSG Reporting ACE.
The calculation of CPS1 would be the same whether or not a BA participates in a RRSG.
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 SDT has added clarifying language to Attachment 2 on how bad data is handled for BAAL.
Oklahoma Gas & Electric

No

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

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

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Question 2 Comment
properly drafted, a Reliability Standard may be enforced in the absence
of specified Measures or Levels of Non-Compliance.” (NOPR and Order
693)

Response: Thank you for your comments.
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.
Independent Electricity System
Operator

No

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

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.

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Response: Thank you for your comments.
The SDT has eliminated the term RRSG Reporting ACE.
The calculation of CPS1 would be the same whether or not a BA participates in a RRSG.
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 SDT has added clarifying language to Attachment 2 on how bad data is handled for BAAL.
SPP Standards Review Group

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 12month 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

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Question 2 Comment
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’.

Response: Thank you for your comments.
The Regulation Reserve3 Sharing Group will be added to the Compliance Registry prior to the standard going into effect.
The SDT has added clarifying language to Requirement R1 to address your concern.
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 believes that the current writing of Requirement R2 is correct and provides the necessary clarity.
The SDT has added the word “Overlap” as you suggested.
Keen Resources Ltd.

No

Manitoba Hydro

Yes

Although Manitoba Hydro is in support of the standard, we have the
following clarifying suggestions:
(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.

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Question 2 Comment
(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.

Response: Thank you for your comments.
1)
2)
3)
4)
5)
6)

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.
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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.
MISO Standards Collaborators

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.

Response: Thank you for your comments.
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.
Duke Energy

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.

Response: Thank you for your comments.
Salt River Project

Yes

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

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
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Question 2 Comment
managed by the Reliability Coordinator through enforcement of existing
standards, but may require changes to current practices.

Response: Thank you for your comments.
EnerVision, Inc.

Yes

Tucson Electric Power Co

Yes

Energy Mark, Inc.

Yes

Texas Reliability Entity

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?

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Question 2 Comment

Response: Thank you for your comments.
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.
American Electric Power

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).

Response: Thank you for your comment. Please refer to our responses above.
MRO NERC Standards Review Forum

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.

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Question 2 Comment

Response: Thank you for your comments.
1 – The 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.
ERCOT

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.

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.
PPL NERC Registered Affiliates

N/A

Modesto Irrigation District

Need a technical justification for the various Epsilon values specified.

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Question 2 Comment

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.
PacifiCorp

PacifiCorp supports this draft.

Response: Thank you for your comments.
PJM Interconnection, L.L.C

PJM is, in general, supportive of this standard with the exception noted
in comments for question 1.

Response: Thank you for your comments. Please refer to our response to Question 1.
Powerex Corp.

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

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
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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.

Response: Thank you for your comments.
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.
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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.
SMUD

See comment in response #1.

Response: Thank you for your comment. Please refer to our response to Question #1.
Tacoma Power

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

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
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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.

Response: Thank you for your comments.
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.
IRC-SRC

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.

Response: Thank you for your comments.
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.
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3.

If you have any other comments on BAL-001-2 that you haven’t already mentioned above, please provide them here:

Summary Consideration: The majority of the commenters provided typographical corrections to the standard and associated
documents.
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.
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.

Organization
Avista

Yes or No
No

Consideration of Comments: Project 2010-14.1
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Question 3 Comment
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.

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Response: Thank you for your 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.
City of Tallahassee

No

MISO Standards Collaborators

No

ACES Standards Collaborators

No

Oklahoma Gas & Electric

No

Bonneville Power Administration

No

Salt River Project

No

PacifiCorp

No

City of Tallahassee

No

City of Tallahassee

No

Manitoba Hydro

Yes

this is not a yes/no question.

(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

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Question 3 Comment
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.

Response: Thank you for your comments.
1)
2)
3)
4)
5)

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

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

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Question 3 Comment
statement for the purposes of documenting compliance.

Response: Thank you for your comments.
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.
Xcel Energy

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.

Response: Thank you for your comments.
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.
SPP Standards Review Group

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

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Question 3 Comment
paragraph, replace ‘that’ with ‘than’ in front of CPS1.

Response: Thank you for your comments.
The SDT has made the correction in the Applicability Section 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 Background Document that you have identified.
Duke Energy

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;

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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.

Response: Thank you for your comments.
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.
The SDT agrees with your comment concerning the field trial. The SDT will look into the concern you have identified.
Exelon

Yes

Exelon is basically fine with structure.

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.

Response: Thank you for your comment.
Idaho Power Company

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Question 3 Comment

Response: Thank you for your comments.
Keen Resources Ltd.

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 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.

Response: Thank you for your comments.
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.
seattle city light

Yes

Consideration of Comments: Project 2010-14.1
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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

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Light cannot support this draft of BAL-001-2.

Response: Thank you for your comments.
The Guidelines Document is anticipated to be posted by July 19, 2013.
NextEra Energy

Yes

The High Frequency Limit (FTLhigh) calculated as Fs + 3Ô•1i
should be changed to Fs + 4Ô•1i

Response: Thank you for your comments.
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.
Tucson Electric Power Co

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.

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).

Response: Thank you for your comments.
American Electric Power

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Response: Thank you for your comments.
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.
EnerVision, Inc.

Yes

Energy Mark, Inc.

Yes

SERC OC Standards Review Group

: 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.

Response: Thank you for your comments.
The SDT is only attempting to recognize the approved variance that was granted to the WECC.
PPL NERC Registered Affiliates

LGE and KU Services is a participant in the BAAL Field Test and
support the implementation of the BAAL standard

Response: Thank you for your comments.
Portland General Electric Company

Consideration of Comments: Project 2010-14.1
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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

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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.

Response: Thank you for your 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.
Powerex Corp.

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

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Question 3 Comment
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 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

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Question 3 Comment
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
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

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Question 3 Comment
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

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Question 3 Comment
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.

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Response: The SDT thank you for your 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.
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.
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.
Tacoma Power

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.

Response: Thank you for your comments.
The SDT does not agree that the requirements in BAL-001-2 are a control methodology.
Texas Reliability Entity

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.”

Response: Thank you for your comments.
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.
Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

78

END OF REPORT

Consideration of Comments: Project 2010-14.1
BAL-001-2 | April 2013

79

Standard BAL-001-2 – 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.
8. The draft standard was posted for 30-day formal industry comment period from June 4,
2012 through July 3, 2012.
9. The draft standard was posted for a 45-day formal industry comment period and initial
ballot from March 12, 2013 through April 25, 2013.
Proposed Action Plan and Description of Current Draft:
This is the second posting of the proposed new standard. This proposed draft standard will be
posted for a 10-day re-circulation ballot from July XX, 2013 through July XX, 2013.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. Recirculation Ballot

July 2013

2. NERC BOT adoption.

August 2013

BAL-001-2
July, 2013

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Standard BAL-001-2 – 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.
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.
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 (or equivalent as
calculated at such time of measurement) of the Balancing Authorities participating in the
Regulation Reserve Sharing Group at the time of measurement.
Reporting ACE: The scan rate values of a Balancing Authority’s Area Control Error (ACE)
measured in MW, which includes the difference between the Balancing Authority’s Net Actual
Interchange and its Net Scheduled Interchange, plus its Frequency Bias obligation, plus any
known meter error. In the Western Interconnection, Reporting ACE includes Automatic Time
Error Correction (ATEC).
Reporting ACE is calculated as follows:
Reporting ACE = (NIA − NIS) − 10B (FA − FS) − IME
Reporting ACE is calculated in the Western Interconnection as follows:
Reporting ACE = (NIA − NIS) − 10B (FA − FS) − IME + IATEC
Where:
NIA (Actual Net Interchange) 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 (Scheduled Net Interchange) is the algebraic sum of all scheduled megawatt
transfers, including Dynamic Schedules, with adjacent Balancing Authorities, and taking
into account the effects of schedule ramps. Balancing Authorities directly connected via
asynchronous ties to another Interconnection may include or exclude 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.

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Standard BAL-001-2 – Real Power Balancing Control Performance
FA (Actual Frequency) is the measured frequency in Hz.
FS (Scheduled Frequency) is 60.0 Hz, except during a time correction.
IME (Interchange Meter Error) is the meter error correction factor and represents the
difference between the integrated hourly average of the net interchange actual (NIA)
and the cumulative hourly net interchange energy measurement (in megawatt-hours).
IATEC (Automatic Time Error Correction) is the addition of a component to the ACE
equation for the Western Interconnection that modifies the control point for the
purpose of continuously paying back Primary Inadvertent Interchange to correct
accumulated time error. Automatic Time Error Correction is only applicable in the
Western Interconnection.
on/off peak

IATEC

= PII

accum

(1 − Y )* H

when operating in Automatic Time Error Correction control mode.

IATEC shall be zero when operating in any other AGC mode.
•

Y = B / BS.

•

H = Number of hours used to payback Primary Inadvertent Interchange energy. The
value of H is set to 3.

•

BS = Frequency Bias for the Interconnection (MW / 0.1 Hz).

•

Primary Inadvertent Interchange (PIIhourly) is (1-Y) * (IIactual - B * ΔTE/6)

•

IIactual is the hourly Inadvertent Interchange for the last hour.

•

ΔTE is the hourly change in system Time Error as distributed by the Interconnection
Time Monitor. Where:
ΔTE = TEend hour – TEbegin hour – TDadj – (t)*(TEoffset)

•

TDadj is the Reliability Coordinator adjustment for differences with Interconnection
Time Monitor control center clocks.

•

t is the number of minutes of Manual Time Error Correction that occurred during the
hour.

•

TEoffset is 0.000 or +0.020 or -0.020.

•

PIIaccum is the Balancing Authority’s accumulated PIIhourly in MWh. An On-Peak and
Off-Peak accumulation accounting is required.
Where:

PII

on/off peak
accum

= last period’s

on/off peak

PII

accum

+ PIIhourly

All NERC Interconnections with multiple Balancing Authorities operate using the principles
of Tie-line Bias (TLB) Control and require the use of an ACE equation similar to the
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Standard BAL-001-2 – Real Power Balancing Control Performance
Reporting ACE defined above. Any modification(s) to this specified Reporting ACE
equation that is(are) implemented for all BAs on an Interconnection and is(are) consistent
with the following four principles will provide a valid alternative Reporting ACE equation
consistent with the measures included in this standard.
1. All portions of the Interconnection are included in one area or another so that
the sum of all area generation, loads and losses is the same as total system
generation, load and losses.
2. The algebraic sum of all area Net Interchange Schedules and all Net Interchange
actual values is equal to zero at all times.
3. The use of a common Scheduled Frequency FS for all areas at all times.
4. The absence of metering or computational errors. (The inclusion and use of the
IME term to account for known metering or computational errors.)
Interconnection: When capitalized, any one of the four major electric system networks in North
America: Eastern, Western, ERCOT and Quebec.

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Standard BAL-001-2 – Real Power Balancing Control Performance
A. Introduction
1.

Title:

Real Power Balancing Control Performance

2.

Number:

BAL-001-2

3.

Purpose:

To control Interconnection frequency within defined limits.

4.

Applicability:
4.1. Balancing Authority
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.
4.1.2 A Balancing Authority that is a member of a Regulation 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 the governing rules for the Regulation Reserve Sharing
Group.
4.2. Regulation Reserve Sharing Group

5.

(Proposed) Effective Date:
5.1.

First day of the first calendar quarter that is twelve 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 twelve 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.

B. Requirements
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. [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 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.[Violation
Risk Factor: Medium] [Time Horizon: Real-time Operations]

C. Measures
M1. The Responsible Entity shall provide evidence, upon request, such as dated calculation
output from spreadsheets, system logs, software programs, or other evidence (either
in hard copy or electronic format) to demonstrate compliance with Requirement R1.
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Standard BAL-001-2 – Real Power Balancing Control Performance
M2. Each Balancing Authority shall provide evidence, upon request, such as dated
calculation output from spreadsheets, 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
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. 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 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. Data required for the calculation of
Regulation Reserve Sharing Group Reporting Ace, or 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 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
Compliance Audits
Self-Certifications
Spot Checking
Compliance Investigation
Self-Reporting
Complaints

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Standard BAL-001-2 – Real Power Balancing Control Performance
1.4. Additional Compliance Information
None.
2.

Violation Severity Levels
R
#

R1

R2

Lower VSL

Moderate VSL

High VSL

Severe VSL

The CPS 1 value
of the
Responsible
Entity, for the
preceding 12
consecutive
calendar month
period, 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 for 45
consecutive
clock-minutes
or less for the
applicable
Interconnection.

The CPS 1 value
of the
Responsible
Entity, for the
preceding 12
consecutive
calendar month
period, is less
than 95 percent,
but greater than
or equal to 90
percent for the
applicable
Interconnection.

The CPS 1 value
of the
Responsible
Entity, for the
preceding 12
consecutive
calendar month
period, is less
than 90 percent,
but greater than
or equal to 85
percent for the
applicable
Interconnection.

The CPS 1 value of the
Responsible Entity, for
the preceding 12
consecutive calendar
month period, is less
than 85 percent for the
applicable
Interconnection.

The Balancing
Authority
exceeded its
clock-minute
BAAL for greater
than 45
consecutive
clock minutes
but for 60
consecutive
clock-minutes
or less for the
applicable
Interconnection.

The Balancing
Authority
exceeded its
clock-minute
BAAL for greater
than 60
consecutive
clock minutes
but for 75
consecutive
clock-minutes
or less for the
applicable
Interconnection.

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

E. Regional Variances
None.
F. Associated Documents
BAL-001-2, Real Power Balancing Control Performance Standard Background Document

BAL-001-2
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Standard BAL-001-2 – 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-001-2
July, 2013

Inclusion of BAAL and WECC Variance and
exclusion of CPS2

Revision

Page 8 of 13

Standard BAL-001-2 – 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 for the most recent preceding 12 consecutive calendar months,
divided by the square of the target frequency bound:
CF =

CF

12 - month

(ε1I ) 2

Where ε1I is the constant derived from a targeted frequency bound for each
Interconnection as follows:
•

Eastern Interconnection ε1I = 0.018 Hz

•

Western Interconnection ε1I = 0.0228 Hz

•

ERCOT Interconnection ε1I = 0.030 Hz

•

Quebec Interconnection ε1I = 0.021 Hz

The rating index CF12-month is derived from the most recent preceding 12 consecutive
calendar 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.
A clock-minute average is the average of the reporting Balancing Authority’s valid
measured variable (i.e., for Reporting ACE (RACE) and for Frequency Error) for each
sampling cycle during a given clock-minute.

 RACE


 − 10 B clock -minute

 ∑ RACE
sampling cycles in clock - minute


nsampling cycles in clock -minute
=
- 10B






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:

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Standard BAL-001-2 – Real Power Balancing Control Performance
 RACE

CFclock -minute = 
* ∆Fclock -minute 

 − 10 B  clock -minute

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).

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) 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

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

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

∑ (CF

month -i

CF12-month =

)(n(one -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
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Standard BAL-001-2 – Real Power Balancing Control Performance
Settings with the Reporting ACE and Frequency Bias Settings of the Balancing Authority
receiving the Regulation Service.

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

When actual frequency is equal to Scheduled Frequency, BAALHigh and BAALLow do not apply.
When actual frequency is less than Scheduled Frequency, BAALHigh does not apply, and
BAALLow is calculated as:
BAAL Low = (− 10 Bi × (FTL Low − FS ))×

(FTL Low − FS )
(FA − FS )

When actual frequency is greater than Scheduled Frequency, BAALLow does not apply and
the BAALHigh is calculated as:
BAALHigh = (− 10 Bi × (FTLHigh − FS ))×

(FTL

High

− FS )

(FA − FS )

Where:
BAALLow 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
Bi is the Frequency Bias Setting for a Balancing Authority (expressed as MW/0.1 Hz)
FA is the measured frequency in Hz.
FS is the scheduled frequency in Hz.
FTLLow is the Low Frequency Trigger Limit (calculated as FS - 3ε1I Hz)
FTLHigh is the High Frequency Trigger Limit (calculated as FS + 3ε1I Hz)
Where ε1I is the constant derived from a targeted frequency bound for each
Interconnection as follows:
•

Eastern Interconnection ε1I = 0.018 Hz

•

Western Interconnection ε1I = 0.0228 Hz

•

ERCOT Interconnection ε1I = 0.030 Hz

•

Quebec Interconnection ε1I = 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

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Standard BAL-001-2 – Real Power Balancing Control Performance
data is available or valid, then that one-minute interval is excluded from the BAAL
calculation and the 30-minute clock would be reset to zero.
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 Overlap Regulation Service.

BAL-001-2
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Standard BAL-001-2 – 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.
8. The draft standard was posted for 30-day formal industry comment period from June 4,
2012 through July 3, 2012.
9. The draft standard was posted for a 45-day formal industry comment period and initial
ballot from March 12, 2013 through April 25, 2013.
Proposed Action Plan and Description of Current Draft:
This is the second posting of the proposed new standard. This proposed draft standard will be
posted for a 10-day re-circulation ballot from July XX, 2013 through July XX, 2013.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. Recirculation Ballot

July 2013

2. NERC BOT adoption.

August 2013

BAL-001-2
July, 2013

Page 1 of 13

Standard BAL-001-2 – 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.
Regulation Reserve Sharing Group: A group whose members consist of two or more Balancing
Authorities that collectively maintain, allocate, and supply the Rregulating Rreserve 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 (or
equivalent as calculated at such time of measurement) of the Balancing Authorities
participating in the Regulation Reserve Sharing Group at the time of measurement.
Reporting ACE: The scan rate values of a Balancing Authority’s Area Control Error (ACE)
measured in MW, which includes the difference between the Balancing Authority’s Nnet
Aactual Interchange and its Net Sscheduled IInterchange, 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). In the Western Interconnection, Reporting
ACE includes Automatic Time Error Correction (ATEC).
Reporting ACE is calculated as follows:
Reporting ACE = (NIA − NIS) − 10B (FA − FS) − IME + IATEC
Reporting ACE is calculated in the Western Interconnection as follows:
Reporting ACE = (NIA − NIS) − 10B (FA − FS) − IME + IATEC
Where:
NIA (Actual Net Interchange) 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 Ttie Llines in their actual interchange, provided they are
implemented in the same manner for Net Interchange Schedule.
NIS (Scheduled Net Interchange) is the algebraic sum of all scheduled megawatt
transfers, including Dynamic Schedules, with adjacent Balancing Authorities, and taking
into account the effects of schedule ramps. Balancing Authorities directly connected via
asynchronous ties to another Interconnection may include or exclude megawatt
transfers on those Ttie Llines 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.

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Standard BAL-001-2 – Real Power Balancing Control Performance
10 is the constant factor that converts the Ffrequency Bbias Ssetting units to MW/Hz.
FA (Actual Frequency) is the measured frequency in Hz.
FS (Scheduled Frequency) is 60.0 Hz, except during a time correction.
IME (Interchange Meter Error) is the meter error correction factor and represents the
difference between the integrated hourly average of the net interchange actual (NIA)
and the cumulative hourly net iInterchange energy measurement (in megawatt-hours).
IATEC (Automatic Time Error Correction) is the addition of a component to the ACE
equation for the Western Interconnection that modifies the control point for the
purpose of continuously paying back Primary Inadvertent Interchange to correct
accumulated time error. Automatic Time Error Correction is only applicable in the
Western Iinterconnection.
on/off peak

IATEC

= PII

accum

(1 − Y )* H

when operating in Automatic Time Error Correction control mode.

IATEC shall be zero when operating in any other AGC mode.
•

Y = B / BS.

•

H = Number of hHours used to payback Primary Inadvertent Interchange energy. The
value of H is set to 3.

•

BS = Frequency Bias for the Interconnection (MW / 0.1 Hz).

•

Primary Inadvertent Interchange (PIIhourly) is (1-Y) * (IIactual - B * ΔTE/6)

•

IIactual is the hourly Inadvertent Interchange for the last hour.

•

ΔTE is the hourly change in system Time Error as distributed by the Interconnection
Time Monitor. Where:
ΔTE = TEend hour – TEbegin hour – TDadj – (t)*(TEoffset)

•

TDadj is the Reliability Coordinator adjustment for differences with Interconnection
Time Monitor control center clocks.

•

t is the number of minutes of Manual Time Error Correction that occurred during the
hour.

•

TEoffset is 0.000 or +0.020 or -0.020.

•

PIIaccum is the Balancing Authority’s accumulated PIIhourly in MWh. An On-Peak and
Off-Peak accumulation accounting is required.
Where:

PII

BAL-001-2
July, 2013

on/off peak
accum

= last period’s

on/off peak

PII

accum

+ PIIhourly

Page 3 of 13

Standard BAL-001-2 – Real Power Balancing Control Performance
All NERC Interconnections with multiple Balancing Authorities operate using the principles
of Tie-line Bias (TLB) Control and require the use of an ACE equation similar to the
Reporting ACE defined above. Any modification(s) to this specified Reporting ACE
equation that is(are) implemented for all BAs on an Iinterconnection and is(are) consistent
with the following four principles will provide a valid alternative Reporting ACE equation
consistent with the measures included in this standard.
1. All portions of the Iinterconnection are included in one area or another so that
the sum of all area generation, loads and losses is the same as total system
generation, load and losses.
2. The algebraic sum of all area Nnet Iinterchange Sschedules and all Nnet
Iinterchange actual values is equal to zero at all times.
3. The use of a common Sscheduled Ffrequency FS for all areas at all times.
4. The absence of metering or computational errors. (The inclusion and use of the
IME term to account for known metering or computational errors.)
Interconnection: When capitalized, any one of the four major electric system networks in North
America: Eastern, Western, ERCOT and Quebec.

BAL-001-2
July, 2013

Page 4 of 13

Standard BAL-001-2 – Real Power Balancing Control Performance
A. Introduction
1.

Title:

Real Power Balancing Control Performance

2.

Number:

BAL-001-2

3.

Purpose:

To control Interconnection frequency within defined limits.

4.

Applicability:
4.1. Balancing Authority
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.
4.1.2 A Balancing Authority that is a member of a Regulation 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 the governing rules for the Regulation Reserve Sharing
Group.
4.2. Regulation Reserve Sharing Group

5.

(Proposed) Effective Date:
5.1.

First day of the first calendar quarter that is twelvesix 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 twelvesix 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.

B. Requirements
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. [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 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.[Violation Risk Factor: Medium] [Time Horizon: Real-time Operations]

C. Measures
M1. The Responsible Entity shall provide evidence, upon request, such as dated calculation
output from spreadsheets, Energy Management sSystem logs, software programs, or

BAL-001-2
July, 2013

Page 5 of 13

Standard BAL-001-2 – Real Power Balancing Control Performance
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 sSystem 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
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. 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 Ccompliance Eenforcement Aauthority 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
Ccompliance Eenforcement Aauthority, to retain specific evidence for a longer
period of time as part of an investigation. Data required for the calculation of
Regulation Reserve Sharing Group Reporting Ace, or 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 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 Ccompliance Eenforcement Aauthority 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
Compliance Investigation

BAL-001-2
July, 2013

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Standard BAL-001-2 – Real Power Balancing Control Performance
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 CPS 1 value
of the
Responsible
Entity, for the
preceding on a
rolling 12
consecutive
calendarmonth
periodbasis, 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 for 45
consecutive
clock -minutes
or less for the
applicable
Interconnection.

The CPS 1 value
of the
Responsible
Entity, for the
precedingon a
rolling 12
consecutive
calendarmonth
periodbasis, 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 for 60
consecutive
clock -minutes
or less for the
applicable
Interconnection.

The CPS 1 value
of the
Responsible
Entity, for the
preceding on a
rolling 12
consecutive
calendarmonth
periodbasis, 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 for 75
consecutive
clock -minutes
or less for the
applicable
Interconnection.

The CPS 1 value of the
Responsible Entity, for
the preceding on a
rolling 12 consecutive
calendar- month
periodbasis, is less than
85 percent for the
applicable
Interconnection.

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

E. Regional Variances
BAL-001-2
July, 2013

Page 7 of 13

Standard BAL-001-2 – Real Power Balancing Control Performance
None.
F. Associated Documents
BAL-001-2, Real Power Balancing Control Performance Standard Background Document
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-001-2
July, 2013

Inclusion of BAAL and WECC Variance and
exclusion of CPS2

Revision

Page 8 of 13

Standard BAL-001-2 – 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 for the most recent preceding consecutive 12 consecutivecalendar months, divided by the square of the target frequency bound:
CF =

CF

12 - month

(ε1I ) 2

Where ε1I is the constant derived from a targeted frequency bound for each
Interconnection as follows:
•

Eastern Interconnection ε1I = 0.018 Hz

•

Western Interconnection ε1I = 0.0228 Hz

•

ERCOT Interconnection ε1I = 0.030 Hz

•

Quebec Interconnection ε1I = 0.021 Hz

The rating index CF12-month is derived from the most recent preceding consecutive 12
consecutive -calendar 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.
A clock-minute average is the average of the reporting Balancing Authority’s valid
measured variable (i.e., for Reporting ACE (RACE) and for Frequency Error) for each
sampling cycle during a given clock -minute.

 RACE


 − 10 B clock -minute

 ∑ RACE
sampling cycles in clock - minute


nsampling cycles in clock -minute
=
- 10B






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:

BAL-001-2
July, 2013

Page 9 of 13

Standard BAL-001-2 – Real Power Balancing Control Performance
 RACE

CFclock -minute = 
* ∆Fclock -minute 

 − 10 B  clock -minute

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).

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) 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

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

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

∑ (CF

month -i

CF12-month =

)(n(one -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
BAL-001-2
July, 2013

Page 10 of 13

Standard BAL-001-2 – Real Power Balancing Control Performance
Settings with the Reporting ACE and Frequency Bias Settings of the Balancing Authority
receiving the Regulation Service.

BAL-001-2
July, 2013

Page 11 of 13

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

When actual frequency is equal to Scheduled Frequency, BAALHigh and BAALLow do not apply.
When actual frequency is less than Scheduled Frequency, BAALHigh does not apply, and
BAALLow is calculated as:
BAAL Low = (− 10 Bi × (FTL Low − FS ))×

(FTL Low − FS )
(FA − FS )

When actual frequency is greater than Scheduled Frequency, BAALLow does not apply and
the BAALHigh is calculated as:
BAALHigh = (− 10 Bi × (FTLHigh − FS ))×

(FTL

High

− FS )

(FA − FS )

Where:
BAALLow 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
Bi is the Frequency Bias Setting for a Balancing Authority (expressed as MW/0.1 Hz)
FA is the measured frequency in Hz.
FS is the scheduled frequency in Hz.
FTLLow is the Low Frequency Trigger Limit (calculated as FS - 3ε1I Hz)
FTLHigh is the High Frequency Trigger Limit (calculated as FS + 3ε1I Hz)
Where ε1I is the constant derived from a targeted frequency bound for each
Interconnection as follows:
•

Eastern Interconnection ε1I = 0.018 Hz

•

Western Interconnection ε1I = 0.0228 Hz

•

ERCOT Interconnection ε1I = 0.030 Hz

•

Quebec Interconnection ε1I = 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

BAL-001-2
July, 2013

Page 12 of 13

Standard BAL-001-2 – Real Power Balancing Control Performance
data is available or valid, then that one-minute interval is excluded from the BAAL
calculation and the 30-minute clock would be reset to zero.
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 Overlap Regulation Service.

BAL-001-2
July, 2013

Page 13 of 13

Implementation Plan
Project 2010-14.1 Balancing Authority Reliability-based Controls
- Reserves
Implementation Plan for BAL-001-2 – Real Power Balancing Control Performance
Approvals Required
BAL-001-2 – Real Power Balancing Control Performance
Prerequisite Approvals
None
Revisions to Glossary Terms
The following definitions shall become effective when BAL-001-2 becomes effective:
Regulation Reserve Sharing Group: A group whose members consist of two or more Balancing
Authorities that collectively maintain, allocate, and supply the Regulating Rreserve required for
all member Balancing Authorities to use in meeting applicable regulating standards.
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 (or equivalent as
calculated at such time of measurement) of the Balancing Authorities participating in the
Regulation Reserve Sharing Group at the time of measurement.
Reporting ACE: The scan rate values of a Balancing Authority’s Area Control Error (ACE)
measured in MW, which includes the difference between the Balancing Authority’s Net Actual
Interchange and its Net Scheduled Interchange, plus its Frequency Bias obligation, plus any
known meter error. In the Western Interconnection, Reporting ACE includes Automatic Time
Error Correction (ATEC).
Reporting ACE is calculated as follows:
Reporting ACE = (NIA − NIS) − 10B (FA − FS) − IME
Reporting ACE is calculated in the Western Interconnection as follows:
Reporting ACE = (NIA − NIS) − 10B (FA − FS) − IME + IATEC

Where:
NIA (Actual Net Interchange) 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 (Scheduled Net Interchange) is the algebraic sum of all scheduled megawatt
transfers, including Dynamic Schedules, with adjacent Balancing Authorities, and taking
into account the effects of schedule ramps. Balancing Authorities directly connected via
asynchronous ties to another Interconnection may include or exclude 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.
FS (Scheduled Frequency) is 60.0 Hz, except during a time correction.
IME (Interchange Meter Error) is the meter error correction factor and represents the
difference between the integrated hourly average of the net interchange actual (NIA)
and the cumulative hourly net Interchange energy measurement (in megawatt-hours).
IATEC (Automatic Time Error Correction) is the addition of a component to the ACE
equation for the Western Interconnection that modifies the control point for the
purpose of continuously paying back Primary Inadvertent Interchange to correct
accumulated time error. Automatic Time Error Correction is only applicable in the
Western Interconnection.
on/off peak

IATEC

= PII

accum

(1 − Y )* H

when operating in Automatic Time Error Correction control mode.

IATEC shall be zero when operating in any other AGC mode.
•

Y = B / BS.

•

H = Number of hours used to payback Primary Inadvertent Interchange energy. The
value of H is set to 3.

•

BS = Frequency Bias for the Interconnection (MW / 0.1 Hz).

•

Primary Inadvertent Interchange (PIIhourly) is (1-Y) * (IIactual - B * ΔTE/6)

•

IIactual is the hourly Inadvertent Interchange for the last hour.

BAL-001-2 – Real Power Balancing Control Performance
July, 2013

2

•

ΔTE is the hourly change in system Time Error as distributed by the Interconnection
Time Monitor. Where:
ΔTE = TEend hour – TEbegin hour – TDadj – (t)*(TEoffset)

•

TDadj is the Reliability Coordinator adjustment for differences with Interconnection
Time Monitor control center clocks.

•

t is the number of minutes of Manual Time Error Correction that occurred during the
hour.

•

TEoffset is 0.000 or +0.020 or -0.020.

•

PIIaccum is the Balancing Authority’s accumulated PIIhourly in MWh. An On-Peak and
Off-Peak accumulation accounting is required.
Where:

PII

on/off peak
accum

= last period’s

on/off peak

PII

accum

+ PIIhourly

All NERC Interconnections with multiple Balancing Authorities operate using the principles
of Tie-line Bias (TLB) Control and require the use of an ACE equation similar to the Reporting
ACE defined above. Any modification(s) to this specified Reporting ACE equation that
is(are) implemented for all BAs on an Interconnection and is(are) consistent with the
following four principles will provide a valid alternative Reporting ACE equation consistent
with the measures included in this standard.
1. All portions of the Interconnection are included in one area or another so that the
sum of all area generation, loads and losses is the same as total system generation,
load and losses.
2. The algebraic sum of all area Net Interchange Schedules and all Net Interchange
actual values is equal to zero at all times.
3. The use of a common Scheduled Frequency FS for all areas at all times.
4. The absence of metering or computational errors. (The inclusion and use of the IME
term to account for known metering or computational errors.)
Interconnection: When capitalized, any one of the four major electric system networks in North
America: Eastern, Western, ERCOT and Quebec.
The existing definition of Interconnection should be retired at midnight of the day immediately prior to
the effective date of BAL-001-2, in the jurisdiction in which the new standard is becoming effective.

BAL-001-2 – Real Power Balancing Control Performance
July, 2013

3

The proposed revised definition for “Interconnection” is incorporated in the NERC approved standards,
detailed in Attachment 1 of this document.
Applicable Entities
Balancing Authority
Regulation Reserve Sharing Group
Applicable Facilities
N/A
Conforming Changes to Other Standards
None
Effective Dates
BAL-001-2 shall become effective as follows:
First day of the first calendar quarter that is twelve 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 twelve 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 twelve-month period for implementation of BAL-001-2 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-001-2 in the particular jurisdiction in which the new
standard is becoming effective.

BAL-001-2 – Real Power Balancing Control Performance
July, 2013

4

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
IRO-005-2a — Reliability Coordination — Current Day Operations

BAL-001-2 – Real Power Balancing Control Performance
July, 2013

5

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-001-2 – Real Power Balancing Control Performance
July, 2013

6

Implementation Plan
Project 2010-14.1 Balancing Authority Reliability-based Controls
- Reserves
Implementation Plan for BAL-001-2 – Real Power Balancing Control Performance
Approvals Required
BAL-001-2 – Real Power Balancing Control Performance
Prerequisite Approvals
None
Revisions to Glossary Terms
The following definitions shall become effective when BAL-001-2 becomes effective:
Regulation Reserve Sharing Group: A group whose members consist of two or more Balancing
Authorities that collectively maintain, allocate, and supply the Rregulating Rreserve 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 (or
equivalent as calculated at such time of measurement) of the Balancing Authorities
participating in the Regulation Reserve Sharing Group at the time of measurement.
Reporting ACE: The scan rate values of a Balancing Authority’s Area Control Error (ACE)
measured in MW, which includes the difference between the Balancing Authority’s Nnet
Aactual Interchange and its Net Sscheduled Interchange, plus its Frequency Bias obligation, plus
any known meter error. In the Western Interconnection, Reporting ACE includes Automatic
Time Error Correction (ATEC).
Reporting ACE is calculated as follows:
Reporting ACE = (NIA − NIS) − 10B (FA − FS) − IME
Reporting ACE is calculated in the Western Interconnection as follows:
Reporting ACE = (NIA − NIS) − 10B (FA − FS) − IME + IATEC

Where:
NIA (Actual Net Interchange) 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 Ttie Llines in their actual interchange, provided they are
implemented in the same manner for Net Interchange Schedule.
NIS (Scheduled Net Interchange) is the algebraic sum of all scheduled megawatt
transfers, including Dynamic Schedules, with adjacent Balancing Authorities, and taking
into account the effects of schedule ramps. Balancing Authorities directly connected via
asynchronous ties to another Interconnection may include or exclude megawatt
transfers on those Ttie Llines 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.
FS (Scheduled Frequency) is 60.0 Hz, except during a time correction.
IME (Interchange Meter Error) is the meter error correction factor and represents the
difference between the integrated hourly average of the net interchange actual (NIA)
and the cumulative hourly net Interchange energy measurement (in megawatt-hours).
IATEC (Automatic Time Error Correction) is the addition of a component to the ACE
equation for the Western Interconnection that modifies the control point for the
purpose of continuously paying back Primary Inadvertent Interchange to correct
accumulated time error. Automatic Time Error Correction is only applicable in the
Western Interconnection.
on/off peak

IATEC

= PII

accum

(1 − Y )* H

when operating in Automatic Time Error Correction control mode.

IATEC shall be zero when operating in any other AGC mode.
•

Y = B / BS.

•

H = Number of hours used to payback Primary Inadvertent Interchange energy. The
value of H is set to 3.

•

BS = Frequency Bias for the Interconnection (MW / 0.1 Hz).

•

Primary Inadvertent Interchange (PIIhourly) is (1-Y) * (IIactual - B * ΔTE/6)

•

IIactual is the hourly Inadvertent Interchange for the last hour.

BAL-001-2 – Real Power Balancing Control Performance
July, 2013

2

•

ΔTE is the hourly change in system Time Error as distributed by the Interconnection
Time Monitor. Where:
ΔTE = TEend hour – TEbegin hour – TDadj – (t)*(TEoffset)

•

TDadj is the Reliability Coordinator adjustment for differences with Interconnection
Time Monitor control center clocks.

•

t is the number of minutes of Manual Time Error Correction that occurred during the
hour.

•

TEoffset is 0.000 or +0.020 or -0.020.

•

PIIaccum is the Balancing Authority’s accumulated PIIhourly in MWh. An On-Peak and
Off-Peak accumulation accounting is required.
Where:

PII

on/off peak
accum

= last period’s

on/off peak

PII

accum

+ PIIhourly

All NERC Interconnections with multiple Balancing Authorities operate using the principles
of Tie-line Bias (TLB) Control and require the use of an ACE equation similar to the Reporting
ACE defined above. Any modification(s) to this specified Reporting ACE equation that
is(are) implemented for all BAs on an iInterconnection and is(are) consistent with the
following four principles will provide a valid alternative Reporting ACE equation consistent
with the measures included in this standard.
1. All portions of the Iinterconnection are included in one area or another so that the
sum of all area generation, loads and losses is the same as total system generation,
load and losses.
2. The algebraic sum of all area Nnet Iinterchange Sschedules and all Nnet Iinterchange
actual values is equal to zero at all times.
3. The use of a common Sscheduled Ffrequency FS for all areas at all times.
4. The absence of metering or computational errors. (The inclusion and use of the IME
term to account for known metering or computational errors.)
Interconnection: When capitalized, any one of the four major electric system networks in North
America: Eastern, Western, ERCOT and Quebec.
The existing definition of Interconnection should be retired at midnight of the day immediately prior to
the effective date of BAL-001-2, in the jurisdiction in which the new standard is becoming effective.

BAL-001-2 – Real Power Balancing Control Performance
July, 2013

3

The proposed revised definition for “Interconnection” is incorporated in the NERC approved standards,
detailed in Attachment 1 of this document.
Applicable Entities
Balancing Authority
Regulation Reserve Sharing Group
Applicable Facilities
N/A
Conforming Changes to Other Standards
None
Effective Dates
BAL-001-2 shall become effective as follows:
First day of the first calendar quarter that is twelvesix 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 twelvesix 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 twelvesix-month period for implementation of BAL-001-2 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-001-2 in the particular jurisdiction in which the new
standard is becoming effective.

BAL-001-2 – Real Power Balancing Control Performance
July, 2013

4

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
IRO-005-2a — Reliability Coordination — Current Day Operations

BAL-001-2 – Real Power Balancing Control Performance
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5

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-001-2 – Real Power Balancing Control Performance
July, 2013

6

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:
 Lack of theoretical justification
 Large ACE treated the same as a small ACE, regardless of direction
 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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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, 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
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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 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
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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
Bias
ACE//Bias
puACE

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:
 Lack of theoretical justification
 Large ACE treated the same as a small ACE, regardless of direction
 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
Bias
ACE//Bias
puACE

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

VSLs for BAL-001-2 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.

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

BAL-001-2 Real Power Balancing Control Performance
VRF and VSL Assignments – February, 2013

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.

7

VSLs for BAL-001-2 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
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

R2.

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.

BAL-001-2 Real Power Balancing Control Performance
VRF and VSL Assignments – February, 2013

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.

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 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

VSLs for BAL-001-2 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.

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

BAL-001-2 Real Power Balancing Control Performance
VRF and VSL Assignments – February, 2013

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.

7

VSLs for BAL-001-2 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
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

R2.

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.

BAL-001-2 Real Power Balancing Control Performance
VRF and VSL Assignments – February, 2013

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.

8

Project 2010-14.1 Balancing Authority Reliability-based
Controls - Reserves
BAL-001-2 Real Power Balancing Control Performance
Mapping Document
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

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

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-001-2 Real Power Balancing Control Performance
February, 2013

2

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

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
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.
R3. Each Balancing Authority providing
Overlap Regulation Service shall

BAL-001-2 Real Power Balancing Control Performance
February, 2013

This Requirement has been
moved into the BAL-001-2

Attachment 1
A Balancing Authority providing Overlap Regulation Service

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
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.
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).

BAL-001-2 Real Power Balancing Control Performance
February, 2013

This Requirement has been
moved into the BAL-001-2
Applicability Section.

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.

5

Project 2010-14.1 Balancing Authority Reliability-based
Controls - Reserves
BAL-001-2 Real Power Balancing Control Performance
Mapping Document
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

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

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-001-2 Real Power Balancing Control Performance
February, 2013

2

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

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
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.
R3. Each Balancing Authority providing
Overlap Regulation Service shall

BAL-001-2 Real Power Balancing Control Performance
February, 2013

This Requirement has been
moved into the BAL-001-2

Attachment 1
A Balancing Authority providing Overlap Regulation Service

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
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.
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).

BAL-001-2 Real Power Balancing Control Performance
February, 2013

This Requirement has been
moved into the BAL-001-2
Applicability Section.

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.

5

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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Ballot Results

Ballot Name: Project 2010 -14.1 BARC BAL -001-2 Final Ballot

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Ballot Period: 7/16/2013 - 7/25/2013
Ballot Type: Final Ballot

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Total # Votes: 324

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Total Ballot Pool: 351
Quorum: 92.31 %  The Quorum has been reached

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Weighted Segment
74.54 %
Vote:
Ballot Results: The Standard has Passed

 Home Page
Summary of Ballot Results

Affirmative
Segment

1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals

Ballot Segment
Pool
Weight

90
10
79
24
75
54
2
6
3
8
351

#
Votes

1
0.9
1
1
1
1
0.2
0.5
0.3
0.7
7.6

#
Votes

Fraction

53
5
48
15
47
34
2
5
1
7
217

Negative
Fraction

0.736
0.5
0.727
0.75
0.758
0.694
0.2
0.5
0.1
0.7
5.665

Abstain
No
# Votes Vote

19
4
18
5
15
15
0
0
2
0
78

0.264
0.4
0.273
0.25
0.242
0.306
0
0
0.2
0
1.935

7
1
7
0
9
3
0
1
0
1
29

11
0
6
4
4
2
0
0
0
0
27

Individual Ballot Pool Results

Segment

1
1
1
1
1
1
1
1

Organization

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

Member

Eric Scott
Paul B Johnson
Robert Smith
John Bussman
James Armke
Kevin Smith
Christopher J Scanlon
Patricia Robertson

https://standards.nerc.net/BallotResults.aspx?BallotGUID=7c47cdd3-ad6c-4d12-aa37-6b9f630081c8[7/26/2013 11:19:18 AM]

Ballot

Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative

Comments

NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1

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
Consolidated Edison Co. of New York
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
El Paso Electric Company
Entergy Transmission
FirstEnergy Corp.
Florida Power & Light Co.
Gainesville Regional Utilities
Great River Energy
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
International Transmission Company Holdings
Corp
JDRJC Associates
KAMO Electric Cooperative
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Long Island Power Authority
Los Angeles Department of Water & Power
Lower Colorado River Authority
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
N.W. Electric Power Cooperative, Inc.
National Grid USA
Nebraska Public Power District
New Brunswick Power Transmission
Corporation
New York Power Authority
Northeast Missouri Electric Power Cooperative
Northern Indiana Public Service Co.
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
Santee Cooper
Seattle City Light

Donald S. Watkins
Tony Kroskey
Michael B Bax
Chang G Choi
Daniel S Langston
Jack Stamper
Paul Morland
Christopher L de Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
Dennis Malone
Oliver A Burke
William J Smith
Mike O'Neil
Richard Bachmeier
Gordon Pietsch
Ajay Garg
Martin Boisvert
Molly Devine
Michael Moltane
Jim D Cyrulewski
Walter Kenyon
Jennifer Flandermeyer
Larry E Watt
Doug Bantam
Robert Ganley
John Burnett
Martyn Turner
William Price
Nazra S Gladu
Danny Dees
Terry Harbour
Andrew J Kurriger
Mark Ramsey
Michael Jones
Cole C Brodine
Randy MacDonald
Bruce Metruck
Kevin White
Julaine Dyke
Robert Mattey
Terri Pyle
Doug Peterchuck
Jen Fiegel
Brad Chase
Daryl Hanson
Bangalore Vijayraghavan
Ryan Millard
John C. Collins
John T Walker
David Thorne
Larry D Avery
Brenda L Truhe
Laurie Williams
Kenneth D. Brown
Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Will Speer
Terry L Blackwell
Pawel Krupa

https://standards.nerc.net/BallotResults.aspx?BallotGUID=7c47cdd3-ad6c-4d12-aa37-6b9f630081c8[7/26/2013 11:19:18 AM]

Negative
Affirmative
Negative
Negative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Abstain
Affirmative
Negative

NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2

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.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator

2

BC Hydro

2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3

California ISO
Electric Reliability Council of Texas, Inc.
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Ameren Services
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
City of Bartow, Florida
City of Redding
City of Tallahassee
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources, Inc.
El Paso Electric Company
Entergy
FirstEnergy Corp.
Florida Municipal Power Agency
Florida Power Corporation
Gainesville Regional Utilities
Georgia Power Company
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
Imperial Irrigation District
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System

Denise Stevens
Rich Salgo
Long T Duong
Tom Hanzlik
Steven Mavis
Robert A. Schaffeld
William Hutchison
John Shaver
Noman Lee Williams
Beth Young
Howell D Scott
Tracy Sliman
John Tolo
Jonathan Appelbaum
Allen Klassen
Lloyd A Linke
Gregory L Pieper
Ken A Gardner
Venkataramakrishnan
Vinnakota
Rich Vine
Cheryl Moseley
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
stephanie monzon
Charles H. Yeung
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
Matt Culverhouse
Bill Hughes
Bill R Fowler
Charles Morgan
John Bee
Peter T Yost
Richard Blumenstock
Jose Escamilla
Michael R. Mayer
Kent Kujala
Connie B Lowe
Tracy Van Slyke
Joel T Plessinger
Cindy E Stewart
Joe McKinney
Lee Schuster
Kenneth Simmons
Danny Lindsey
Brian Glover
Paul C Caldwell
David Kiguel
Jesus S. Alcaraz
Garry Baker
Theodore J Hilmes
Charles Locke
Gregory D Woessner
Mace D Hunter
Jason Fortik

https://standards.nerc.net/BallotResults.aspx?BallotGUID=7c47cdd3-ad6c-4d12-aa37-6b9f630081c8[7/26/2013 11:19:18 AM]

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Negative
Negative
Affirmative
Abstain
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Abstain
Affirmative

NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5

Louisville Gas and Electric Co.
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
Mississippi Power
Modesto Irrigation District
Muscatine Power & Water
National Grid USA
Nebraska Public Power District
New York Power Authority
Northeast Missouri Electric Power Cooperative
NW Electric Power Cooperative, Inc.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Portland General Electric Co.
Potomac Electric Power 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.
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
Wisconsin Electric Power Marketing
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
Constellation Energy Control & Dispatch,
L.L.C.
Consumers Energy Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Georgia System Operations Corporation
Madison Gas and Electric Co.
Modesto Irrigation District
Ohio Edison Company
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
Utility Services, Inc.
Wisconsin Energy Corp.
AEP Service Corp.

Charles A. Freibert
Stephen D Pogue
Greg C. Parent
Roger Brand
Jeff Franklin
Jack W Savage
John S Bos
Brian E Shanahan
Tony Eddleman
David R Rivera
Skyler Wiegmann
David McDowell
Donald Hargrove
Blaine R. Dinwiddie
David Burke
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Thomas G Ward
Mark Yerger
Jeffrey Mueller
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
James R Keller
Michael Ibold
Herb Schrayshuen
Kenneth Goldsmith
Kevin Koloini
Duane S Dahlquist
Reza Ebrahimian

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative

Tim Beyrle
Nicholas Zettel
John Allen

Affirmative
Affirmative

Margaret Powell

Affirmative

Tracy Goble
Russ Schneider
Frank Gaffney
Guy Andrews
Joseph DePoorter
Spencer Tacke
Douglas Hohlbaugh
Henry E. LuBean

Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative

John D Martinsen

Affirmative

Mike Ramirez
Hao Li
Steven R Wallace
Keith Morisette
Brian Evans-Mongeon
Anthony Jankowski
Brock Ondayko

Negative
Negative
Affirmative
Negative

https://standards.nerc.net/BallotResults.aspx?BallotGUID=7c47cdd3-ad6c-4d12-aa37-6b9f630081c8[7/26/2013 11:19:18 AM]

Affirmative
Negative

NERC Standards
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
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
Consolidated Edison Co. of New York
Consumers Energy Company
Dairyland Power Coop.
Detroit Edison Company
Detroit Renewable Power
Dominion Resources, Inc.
Duke Energy
Electric Power Supply Association
Entergy Services, Inc.
Exelon Nuclear
FirstEnergy Solutions
Florida Municipal Power Agency
Gainesville Regional Utilities
Great River Energy
Imperial Irrigation District
JEA
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
NextEra Energy
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
PPL Generation LLC
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.
South Feather Power Project
Southern California Edison Company
Southern Company Generation
Tacoma Power

Sam Dwyer
Scott Takinen
Matthew Pacobit
Clement Ma
Mike D Kukla
Francis J. Halpin
Shari Heino
Jeanie Doty
Paul A. Cummings
Karen Webb
Steve Rose
Michael Shultz
Wilket (Jack) Ng
David C Greyerbiehl
Tommy Drea
Alexander Eizans
Marcus Ellis
Mike Garton
Dale Q Goodwine
John R Cashin
Tracey Stubbs
Mark F Draper
Kenneth Dresner
David Schumann
Karen C Alford
Preston L Walsh
Marcela Y Caballero
John J Babik
Brett Holland
James M Howard
Dennis Florom
Kenneth Silver
Karin Schweitzer
S N Fernando
David Gordon
Steven Grego
Neil D Hammer
Mike Avesing
Don Schmit
Wayne Sipperly
Allen D Schriver
William O. Thompson
Bernard Johnson
Leo Staples
Mahmood Z. Safi
Richard K Kinas
Bonnie Marino-Blair
Roland Thiel
Matt E. Jastram
Tim Hattaway
Annette M Bannon
Tim Kucey
Michiko Sell
Lynda Kupfer
Susan Gill-Zobitz
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Edward Magic
Kathryn Zancanella
Denise Yaffe
William D Shultz
Chris Mattson

https://standards.nerc.net/BallotResults.aspx?BallotGUID=7c47cdd3-ad6c-4d12-aa37-6b9f630081c8[7/26/2013 11:19:18 AM]

Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative

NERC Standards
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
7
7

Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
U.S. Bureau of Reclamation
Westar Energy
Wisconsin Electric Power Co.
Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
APS
Associated Electric Cooperative, Inc.
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Con Edison Company of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy
El Paso Electric Company
Entergy Services, Inc.
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Energy
Manitoba Hydro
Modesto Irrigation District
Muscatine Power & Water
New York Power Authority
Northern Indiana Public Service Co.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
Power Generation Services, Inc.
Powerex Corp.
PPL EnergyPlus LLC
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
Southern California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
EnerVision, Inc.
Steel Manufacturers Association

RJames Rocha
Scott M. Helyer
David Thompson
Mark Stein
Melissa Kurtz
Martin Bauer
Bryan Taggart
Linda Horn
Liam Noailles
Edward P. Cox
Jennifer Richardson
Randy A. Young
Brian Ackermann
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Shannon Fair
David Balban
David J Carlson
Louis S. Slade
Greg Cecil
Tony Soto
Terri F Benoit
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Packer
Brenda Hampton
Blair Mukanik
James McFall
John Stolley
Saul Rojas
Joseph O'Brien
Douglas Collins
Kelly Cumiskey
Carol Ballantine
Ty Bettis
Stephen C Knapp
Daniel W. O'Hearn
Elizabeth Davis
Peter Dolan
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
Kenn Backholm
Lujuanna Medina

Affirmative
Abstain
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Abstain

John J. Ciza

Affirmative

Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson

Negative
Affirmative
Affirmative
Negative

Peter H Kinney
David F Lemmons
Thomas W Siegrist
James Brew

https://standards.nerc.net/BallotResults.aspx?BallotGUID=7c47cdd3-ad6c-4d12-aa37-6b9f630081c8[7/26/2013 11:19:18 AM]

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative

Negative
Affirmative
Affirmative
Affirmative

NERC Standards
8
8
8
8
8
8
9
9
9
10
10
10
10
10
10
10
10

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
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council

Roger C Zaklukiewicz
Edward C Stein
Robert Blohm
Debra R Warner
Howard F. Illian
Terry Volkmann

Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative

Donald Nelson

Affirmative

Norman Harryhill

Negative

Diane J. Barney

Negative

Linda Campbell
Russel Mountjoy
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B Edge
Donald G Jones
Steven L. Rueckert

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Washington Office: 1325 G Street, N.W. : Suite 600 : Washington, DC 20005-3801

Copyright © 2012 by the North American Electric Reliability Corporation.  :  All rights reserved.
A New Jersey Nonprofit Corporation

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Exhibit H
Standard Drafting Team Roster for Project 2010-14.1

Project 2010-14.1 BARC - Reserves
Name and Title 
Glenn Stephens ‐ 
Chair 

Company 
Santee Cooper 

Contact Info 
843.761.8000 
x‐4482 
glenn.stephens
@santeecooper.
com 

Bio 
Mr. Stephens is Manager of System Planning 
at Santee Cooper. His responsibilities include 
managing the planning of the Bulk Electric 
System as well as planning, designing, and 
operating the communications system.  He 
earned a Bachelor of Science in Electrical 
Engineering degree from Clemson University 
in 1983 and Master of Business Administration 
from University of South Carolina in 1995.   He 
has 31 years of experience in the electric 
power industry having spent his entire career 
with Santee Cooper and has worked in many 
areas including: system operations, system 
planning, metering operations, 
communication operations and planning, 
distribution operations, protection operations, 
and substations operations.  He is a registered 
Professional Engineer in state of South 
Carolina and is NERC certified operator at the 
RC level.  

Tom Siegrist – 
Vice‐Chair 

Brickfield, 
Burchette, Ritts 
and Stone, P.C. 

678. 520.6954 
tom.siegrist@bb
rslaw.com 

Mr. Siegrist has 40 years of electric utility 
experience, including electric system 
operations and maintenance, system 
protection and control, engineering design, 
and system planning.  In his current position 
with Brickfield, Burchette, Ritts and Stone 
(BBRS), Mr. Siegrist provides electric industry 
related engineering consulting services to the 
firm and its clients.   

Before joining BBRS, Mr. Siegrist was a 
founding owner of the consulting firm, 
EnerVision, Inc. where he led the firm’s 
transmission, system operations and NERC 
compliance practice areas for 15 years.  Prior 
to the formation of EnerVision, Mr. Siegrist 
served for 20 years in several senior positions 
with Oglethorpe Power Corporation (OPC) 
including Vice President positions in Electric 
System Operations, Electric System Planning, 
Transmission Engineering, 
Telecommunications, and Transmission 
Operations & Maintenance.  In Electric System 
Operations, Tom developed and directed 
efforts to establish OPC’s control center 
operations, enabling Oglethorpe Power to 
participate in power markets for the first 
time.  This included the implementation of 
real‐time operations and compliance with 
NERC/SERC reliability standards.  Prior to 
joining Oglethorpe Power Mr. Siegrist worked 
at Florida Power & Light Company as a System 
Protection Test Engineer.   

Mr. Siegrist holds a Bachelor Degree in 
Electrical Engineering from The Georgia 
Institute of Technology, and is a registered 
Professional Engineer in the State of Georgia. 

Gerry Beckerle 

Ameren 

314.554.6413 
GBeckerle@ame
ren.com 

Gerald D. Beckerle, Senior Transmission 
Operations Supervisor, Ameren Services, St. 
Louis, MO, has a BSEE from the University of 
Missouri, Columbia.  He has been with 
Ameren for 33 years, 26 of those years in 
System Operations, which has been or 
currently responsible for Transmission, 
Generation, and daily interchange. 

Current activities include: 
NERC OC IOU Representative 2013‐
2015, serving on OC executive 
committee 
NERC Resources Subcommittee 
Chairman 2014‐2016 
NERC Balancing Authority Reliability 
Based Controls Standard Drafting 
Team member 
SERC Operating Committee Member 

Past Activities included: 
            NERC Operating Committee Member 
RE Representative 2011‐2013 
SERC Operating Committee Chairman 
2011‐2013 
NERC Frequency Response Standard ‐  
Drafting Team Contributor 
Balancing Authority Controls SAR and 
SDT member prior to merging into the 
BARC SDT. 
Midwest Reserve Sharing Group ‐ 
representative for Ameren 
RFC Version Zero Standards Drafting 
Team member 
MAIN Operating Reserve 
Subcommittee member 

Howard Illian 
President 

Energy Mark, Inc. 

847‐913‐5491 
howard.illian@e
nergymark.com 

Howard F. Illian graduated from Carnegie 
Institute of Technology (Carnegie‐Mellon 
University) in 1970 with a B.S. in Electrical 
Engineering.  From 1970 until 1982 he worked 
for ComEd in the field of Operations Research, 
and was Supervisor, Economic Research and 
Load Forecasting from 1976 until he was 
reassigned to Bulk Power Operations in 1982 
where he was Technical Services Director 
when he retired in 1998.  He is now President 
of Energy Mark, Inc., a consulting firm 
specializing in the commercial relationships 
required by restructuring.  He has authored 
numerous papers, and has testified as an 
expert witness before the Illinois EPA, the 
Federal EPA, the Illinois Commerce 
Commission, the Public Utility Commission of 
Texas, and the Federal Energy Regulatory 
Commission.  He has developed and applied 
several new mathematical techniques for use 
in simulation and decision making.  He has 
served on the NERC Performance 
Subcommittee, the Interconnected 
Operations Services Implementation Task 
Force, the Joint Inadvertent Interchange Task 
Force, and the NAESB Inadvertent Interchange 
Payback Task Force.  Recent work includes 
significant contributions to the development 
of new NERC Control Performance Standards 
including the Balancing Authority Ace Limit 
and a suggested mathematical foundation for 
control based on classical statistics.  His 
current research concentrates on the 
development of technical definitions for 
Ancillary or Reliability Services including 
frequency response and their market 
implementation. 

David Lemmons – 
Chair 
Senior Consultant 

Xcel Energy, Inc 

303.628.2813     
david.f.lemmons
@xcelenergy.co
m 

David Lemmons began his career in the 
electric industry with Southwestern Public 
Service Company (SPS) in Amarillo, Texas in 
1989.  He spent 8 years in the Rates and 
Regulation Department where he performed 
rate of return analyses, designed rates and 
worked with other regulatory issues.  In 1997, 
David moved to the Energy Trading 
Department during the merger between SPS 
and Public Service Company of Colorado 
(PSCo).  In this capacity, with Xcel Energy and 
its predecessor, New Century Energies, he 
analyzed the electric system loads and 
resources for day‐ahead and real‐time 
operations and trading, working with 
generation and fuel procurement to ensure 
resources were ready and available to serve 
loads.  From 2001 to 2013, in the positions of 
Manager and Senior Manager of Market 
Operations, he has represented Xcel Energy at 
electric reliability, RTO development and 
system operation meetings throughout the 
United States as well as providing support for 
state and Federal regulatory proceedings.  In 
2013, David moved into the Energy Supply 
Compliance area where he works with 
generators to ensure compliance with 
applicable NERC and Regional standards. He 
has a Masters of Science in Finance and 
Economics from West Texas A&M University. 

Clyde Loutan 
Senior Advisor 

California ISO 

916‐608‐5917 
[email protected]
om 

LeRoy Patterson 

Puget Sound 
Energy 

425.882.4433 
Leroy.Patterson
@pse.com 

Clyde Loutan is presently a Senior Advisor at 
the California Independent System Operator 
Corporation (ISO) focusing on power system 
operation performance, and is the lead 
investigator for the ISO’s renewable resource 
integration technical studies. He is a technical 
subject matter expert on power grid planning, 
system operations, and renewable energy 
integration. Mr. Loutan previously worked at 
the Pacific Gas and Electric Company for 14 
years in various capacities such as Real Time 
System Operations, Transmission Planning and 
High Voltage Protection. 

Mr. Loutan is a licensed professional engineer 
in the State of California.  He holds B.S. and 
M.S. degrees in Electrical Engineering from 
Howard University in Washington D.C., and is 
a senior member of the IEEE. 

Mr. Patterson is an executive with years of 
experience and extensive knowledge of 
electric system operations, SCADA and Energy 
Management Systems (EMS), regulations, and 
the North American Electric Reliability 
Corporation (NERC) and Western Electricity 
Coordinating Council (WECC) standards 
development and compliance programs.  
Since September 2012, Mr. Patterson has 
worked at Puget Sound Energy (PSE) training 
System Operators.  His utility career began as 
a transmission planner for Pacific Gas & 
Electric.  He has 18+ years working in 
operations at Montana Power Company and 
NorthWestern Energy, 3 years as director of 
operations at the Western Electricity 
Coordinating Council, and 4+ years at 
Patterson Consulting, Inc. and Utility Systems 
Efficiencies, Inc.  Mr. Patterson has been 
active within electric industry organizations 
such as Northwest Power Pool Operating 
Committee, Western Systems Coordinating 
Council (now WECC), and NERC.  His activities 
in these and other regional forums have 
included leadership positions in many cases 
such as being the chair of the operating 
committee of both the NWPP and WSCC.   

Mike Potishnak 
Principal Engineer 

Spriteland Energy 

413‐323‐8834 
[email protected]
et 

Mark Prosperi‐
Porta 

BC Hydro 

Mark.Prosperi‐
Porta@bchydro.
com 

Tom Pruitt 

Duke Energy 
Carolinas, LLC 

704‐382‐4676 
Tom.Pruitt@duk
e‐energy.com 

Mike Potishnak is President of Spriteland 
Energy and is representing NPCC in the 
development of Balancing Standards as a 
consultant.  Mike has a B.S in E.E. and an M.S. 
in M.E., with over 40 years of utility 
experience, working previously for Con 
Edison, Public Service Colorado, and ISO New 
England. 

Mr. Prosperi‐Porta joined BC Hydro in 1990 
after graduating with a Bachelor of Applied 
Science in Electrical Engineering.  Worked in 
engineering, design, market operations and 
system operations over the next 24 years.  
Currently is a System Control Manager and 
oversees the Real‐time operation of 
distribution, transmission, generation and 
bulk electric system in BC. 

Tom Pruitt is a Principal Engineer with Duke 
Energy and has over 30 years’ experience in 
almost all facets of operation in a vertically‐
integrated utility, the last 17 in system 
operations.  He chairs sub‐regional operating 
and reserve sharing group committees and is 
a member of the NERC Resources 
Subcommittee.  He is his company’s subject 
matter expert (SME) on BAL and COM 
standards.  He has a BSEE from North Carolina 
State University and is a NERC‐certified 
Reliability Coordinator and licensed 
Professional Engineer (NC). 

Jerry Rust 
President 

Northwest Power 
Pool 

Steve Swan 

MISO 

503.445.1074 
Jerry D. Rust joined the Northwest Power Pool 
jerry.rust@nwpp January 1, 2001 as President. For the majority 
.org 
of  2000,  Jerry  consulted  on  power  issues  for 
several  software  companies.  Prior  to  that,  he 
worked  at  PacifiCorp  for  23  years,  where  he 
served  as  managing  director  of  PacifiCorp’s 
revenue  organization  and  managing  director 
of  the  transmission  systems  group.  Jerry 
joined  PacifiCorp  in  1977  as  an  engineer  and 
held  positions  in  power  resources,  financial 
analysis,  field  operations,  customer  service, 
sales support and national sales. 

Mr. Rust was graduated from the University of 
Wyoming with a degree in electrical 
engineering. He has furthered his education 
with numerous courses from various schools 
(University of Washington, Washington State 
University, Colorado School of Mines, and 
others). Jerry is one of the Western Electricity 
Coordinating Council’s North American 
Electric Reliability Council Operating 
Committee Representatives. 

317‐249‐5075 
Steve Swan is the Senior Manager of Dispatch 
SSwan@misoen and Balancing at the Midcontinent 
ergy.org 
Independent System Operator, Inc. where he 
is the manager of all system wide market 
dispatch and balancing functions for a fleet of 
over 100,000 MW of MISO controlled 
generation. 

Tom Washburn 
Executive Director 

Florida Municipal 
Power Pool 

407‐434‐4228  
TWashburn@ou
c.com 

With over 40 years of experience, Tom 
Washburn has provided a diverse set of 
services to Orlando Utilities Commission and 
the Florida Municipal Power Pool. As Vice 
President of the Transmission Unit at Orlando 
Utilities Commission, he was responsible for 
the planning, regulatory permitting, 
construction and operation of over 300 miles 
high voltage transmission lines, over 30 high 
voltage substations, and the 24‐by‐7 system 
operations of the transmission and generation 
system.  As the Chief Information Officer at 
Orlando Utilities Commission, Washburn was 
responsible for all of the Information 
Technology including microcomputer support, 
computer applications, computer hardware, 
telecommunication and the fiber optics data 
communications.  In other management roles 
at Orlando Utilities Commission, he was 
responsible for financial planning, load 
forecasting, rate design, wholesale marketing, 
and generation planning.  Tom Washburn 
helped form the Florida Municipal Power Pool, 
which started operation in July 1988.  As the 
first Executive Director of the Florida 
Municipal Power Pool, since May. 2006, 
Washburn is responsible for the reliable, 
economic operation of more than 4,500 
megawatts of generation serving 20 municipal 
utilities in Florida, compliance with the North 
America Reliability Corporation Reliability 
Standards, and overseeing the clearinghouse 
price process for the Pool.   

Robert Cummings  NERC 
Director, Reliability 
Initiatives and 
System Analysis 

404‐446‐9717  
bob.cummings@
nerc.net  

Mr. Cummings joined NERC in 1996 and has 
extensive experience in the industry in system 
planning, operations engineering, and wide 
area planning.  He holds a Bachelor of Science 
Degree in Power System Engineering from 
Worcester Polytechnic Institute and is an IEEE 
Senior Member. 
His geographically diverse experience includes 
Central Vermont Public Service Corporation in 
System Planning (generation and 
transmission), Public Service Company of New 
Mexico, and the East Central Reliability 
Coordination Agreement (ECAR). 
Mr. Cummings was the “father” of power 
interchange transaction “tagging” and the 
Interchange Distribution Calculator, which 
shows loading contributions on key system 
transmission interfaces, or “flowgates,” for 
the Eastern Interconnection. 
The Reliability Initiatives and System Analysis 
group acts provides a consulting engineering 
function within NERC, performing deep‐dive 
forensic engineering analysis of major system 
disturbances and providing subject matter 
expertise to standards drafting teams and 
various other areas of NERC staff. 
Cummings was intimately involved in the 
investigation team of the 2003 blackout as a 
team leader and the more recent September 
8, 2011 Arizona‐Southern California Outage 
analysis.  In both instances he led multiple 
teams with responsibilities in the sequence of 
events development, modeling and studies 
(powerflow and dynamics analysis), and 
transmission/generation performance areas. 
From 2005 through 2009, he directed the 
NERC Event Analysis and Information 
Exchange program, directing or working on 12 
major disturbance analyses. 
Mr. Cummings was instrumental in the 
founding of the NERC System Protection and 
Controls Task Force, now the System 
Protection and Control Subcommittee, acting 
as the staff coordinator from 2004 through 
2009. 

Darrel Richardson 
Standards 
Developer 

NERC 

609‐613‐1848 
Darrel.richardso
[email protected] 

Mr. Cummings is the staff coordinator for the 
NERC System Analysis and Modeling 
Subcommittee and is the technical advocate in 
the North American Synchro‐Phasor Initiative.  
He is also the technical director of the NERC 
System Protection and Control Performance 
Improvement Initiative, the Modeling 
Improvements Initiative, and the Frequency 
Response Improvement Initiative. 

Darrel Richardson joined the NERC staff as a 
Standards Developer.  In this role he facilitates 
and provides guidance to drafting teams in 
the development of technically excellent and 
timely reliability standards for the reliable 
operation and planning of the bulk power 
system.  Darrel began his career with NERC in 
November 2007.  
Darrel has extensive experience in the utility 
industry having spent over 37 years with 
Illinois Power Company.  In his tenure at 
Illinois Power he held several different 
positions in the Engineering, Planning and 
Operations groups.  Among the position he 
has held are Transmission Coordinator, 
Generation Coordinator, Manager Wholesale 
Marketing, Manager Wholesale Marketing 
and Trading, Director Generation Control and 
Manager Compliance.